bluuebunny/crossref_metadata_2025_split huggingface dataset:
Estimating the Permeability Field Using the Bayesian Inference and Principal Component Analysis
Authors: Zhang Zhen , He Xupeng , Li Yiteng , Alsinan Marwa , Kwak Hyung , Hoteit Hussein 
Published: October 2023

Abstract
Surrogate modeling is essential in reducing computational costs for history-matching applications. Yet, traditional deep learning-based surrogate models cannot cope with high dimensional input parameters, such as the permeability field. This work introduces a robust method to automate the history matching process utilizing the Bayesian inversion assisted by a hybrid convolutional neural network and long short-term memory (CNN-LSTM) model and principal component analysis (PCA) method. The method includes five main steps. Step 1: Generate a high-spatial permeability field using a geostatistical approach. Step 2: use the PCA to reduce the dimensionality of the permeability fields, followed by using PCA to generate permeability fields and perform simulations. Step 3: construct the CNNLSTM to map the nonlinear relationship between the extracted features from PCA and the sequential outputs, such as the pressure response. Here, Bayesian optimization is employed to automate hyperparameter tuning. Step 4: perform the Bayesian inversion to inverse the high dimensional inputs, e.g., permeability field, in which the CNN-LSTM serves as the forward model to reduce the computational cost. The inversed PCA features are then fed into the PCA to recover the high dimensional inputs. Step 5: check convergence and if the errors are significant between the inversed high dimensional permeability field and the ground truth, revisit the construction of the CNN-BiLSTM and the prior information for the uncertainty parameters. A 2D reservoir model demonstrates the proposed history-matching method. We can inverse the high dimensional inputs (e.g., permeability field) with minor errors between the prediction and ground truth. We propose a Bayesian inversion assisted by a hybrid CNN-LSTM model and PCA method for high-dimensional parameter inversion, which is superior to the traditional models regarding accuracy and efficiency. This method enables us to perform history matching for reservoir simulation with high dimensional inputs and significant uncertainties.
Assessment of DFIT Analysis Using Laboratory Experiments
Authors: Ye Zhi , Ghassemi Ahmad 
Published: October 2023

Abstract
Reliable knowledge of the magnitudes and orientations of in-situ stress is crucial for conducting scientific and engineering activities in the subsurface, especially with regards to subsurface energy and storage applications. A commonly used technique for determining the minimum principal stress is to interpret the fracture closure pressure from the pressure decline transient during the shut-in phase of a minifrac test or a diagnostic fracture injection test (DFIT). However, current minifrac or DFIT analysis methods for interpreting fracture closure pressure often yield inconsistent results, leading to large uncertainties in determining the minimum principal stress. This paper presents a series of small-scale laboratory hydraulic fracturing experiments conducted under true-triaxial compression. The injection scheme consists of a hydraulic fracturing cycle followed by a few fracture propagation cycles and several injection/falloff (DFIT) cycles. The wellbore pressure and acoustic emission (AE) activities of each cycle were concurrently measured to monitor fracture initiation, propagation, and closure during fluid injection and shut-in. The pressure data were used to interpret S3 using different hydraulic fracturing-based methods. The results illustrate that the spatial-temporal evolution of AE activities is well associated with fracture propagation. In relatively low permeable rocks (Test 1 and Test 2), fracture reopening pressure generally provides a reliable estimate of the minimum principal stress (S3). ISIP consistently provides a relatively higher estimate of S3 and can be used as an upper limit for constraining S3. Fracture closure was observed using the so-called "tangent" method in all injection/falloff cycles. However, the "tangent" method using a signature close to the peak GdP/dG tends to significantly underestimate S3. The "compliance" method offers a relatively objective (yet still low) estimate of closure pressure. The signature associated with the change in system stiffness or compliance is observed but not consistently in every DFIT cycle. In the relatively high permeable Scioto Sandstone test (Test 3), the G-function plots exhibit a "normal" leak off behavior, and the "tangent" method provides a good stress estimate, and the compliance method lacks a clear signature for determining fracture closure. The stress interpretation results demonstrate that the process of fracture closure is highly impacted by rock properties, such as permeability and elastic moduli, and cyclic injection operations.
Ensuring Effective Downhole Corrosion Control Management Through the Newly Integrated Corrosion Monitoring Surveillance System
Authors: Abdulghani Ahmed , Muailu Husain , Bukhamseen Ahmad , Haque Mohammad 
Published: October 2023

Abstract
Corrosion challenges in production and injection wells are common in the oil and gas industry. The detrimental outcomes of corrosion affect the service life of a well. The necessity of dependable corrosion management solutions that can precisely measure corrosion rates is essential when taking into consideration the expense of maintenance and repair because of corrosion and material failures. In this paper, a successful deployment of a newly re-designed downhole corrosion monitoring tool with a custom-designed Downhole Coupon Holder Assembly (DCHA) is discussed.
Electrical resistance (ER) corrosion probes are widely used in the petroleum industry for corrosion rate surveillance. To keep track of metal loss, the ER probes measure the electrical resistance, which rises as the size of the consumable test coupon reduces. The weight loss corrosion coupons, one of the oldest and most well-known corrosion monitoring techniques, are still widely used to this day. Examining the Mils-Per-Year (MPY) rate of corrosion on a used coupon can give an indication of the material's durability.
The integrated innovation, the ER+ tool, was equipped with a specially configured resistivity probe to measure downhole temperature and metal loss data and hosted with a set of six metal coupons in a single coupon holder. It was deployed in a water supply well for a period of 83 days. After a successful retrieval of the tool, the downhole data was downloaded and the metal coupons were analyzed for metal loss profiling, surface profilometry, X-Ray Fluorescence (XRF), and Scanning Electron Microscopy (SEM) imaging analysis.
The results conclude that the ER+ tool offers an excellent platform allowing downhole screening of multiple tubing metallurgies for future tubing materials selection and design in a single deployment, i.e., shortening the overall well downtime. In addition, the ER+ tool enables the evaluation of corrosion inhibitor efficacy for different metallurgies. The results will be further used to design an effective and timely downhole inhibitor injection batch treatment schedule and doses for better downhole integrity maintenance. In the long run, the operational and maintenance costs are foreseen to be reduced significantly.
The deployment of the integrated ER+ tool showed an excellent understanding of the recorded corrosion rate, and temperature data and establishes the effectiveness of corrosion inhibitor treatments with improved battery life for better surveillance monitoring.
Real-Time Drilling Fluid Measurements Provide Value Via Data-Driven Decision Making for Cost-Sensitive Unconventional Environments
Authors: Petty W. , Offenbacher M. , Jara R. , Rabb C. , Unrau S. 
Published: October 2023

Abstract
A new approach to real-time automated drilling fluid measurement systems leads to enhanced collaboration and decision making between field and remote operations personnel. The approach is based on straight forward technology that can easily be understood by all, operated by field personnel, and robust enough for fast paced unconventional operations. The sensor information offers real-time actionable data without the demand to replicate the traditional daily mud report, streamlining wellsite activities for drilling fluid treatment as fluid conditions change.
The automated drilling fluid measurement system (mud skid) was designed for reliability and simplicity. The idea is to use trending data over the single data point mud check to drive real time decision making across teams. Rather than replace the fluids specialist on location it enhances their role to drive operational excellence and consistency in their day-to-day rig support. Everyday across multiple rigs, drilling fluids specialists use the data to adjust treatment schedules, optimize activities, and capture unplanned events as early as possible to lower treatment cost with the support of the remote operations center (ROC). The ROC's monitoring activities drive fluid enhancements across multiple locations via data transparency and analysis, sharing of best practices, and event detection. With a few proven and fit for purpose sensors, the mud skid adds value within the cost limits of the unconventional well market.
There is an opportunity for value generation via the use of economical drilling fluid sensors where costs traditionally limit full-scale automated drilling fluid measurements. The mud skid unit provides sufficient data to generate value without prohibitive expenses. The mud skid unit and the data collected are now part of standard operations across multiple rigs and basins. The data streams, available in real-time to everyone from the derrick hand to the drilling engineer, have created a new workflow for decision-making, fluid maintenance, trouble-shooting, and early event detection. As more events are captured by the sensors, there are additional opportunities to train machine learning algorithms and develop predictive models.
This paper will review the development process, deployment, and delivery of the mud skid unit with case histories demonstrating the advantages and opportunities for simple, real-time data streams.
CO2 Sequestration in the Arbuckle Group: Flow Simulation in Osage County, Oklahoma
Authors: Hamzat A. A. , Milad B. , Moghanloo R. G. 
Published: October 2023

Abstract
This paper provides a valuable foundation for the potential establishment of a carbon dioxide (CO2) sequestration project in Osage County, Oklahoma. Given the current global climate crisis and the resultant efforts to reduce atmospheric CO2 levels, these types of initiatives are expected to increase in frequency and scale. This study focuses on the Arbuckle Group, a saline aquifer and carbonate rocks that has been identified as a potential large-scale CO2 storage reservoir in a previous publication by Milad et al. (2023).
A 3D geological model was constructed integrating core and well log data, allowing for the estimation of stratigraphic and petrophysical properties of the Arbuckle Group in Osage County. A 30-year injection period of over 50 million metric tons of CO2 was then simulated, incorporating the permeabilities and porosities from the geological model.
This process involved building a compositional simulation model with one injection well, with the formation divided into 10 layers and injections occurring in the bottom four. These layers were chosen based on the depth of existing injection wells, as well as the existence of natural fractures that enhance the permeability distribution, thus supporting large-scale CO2 injection at low pressure. A subsequent 50-year post-injection study was also conducted to monitor pressure buildup and CO2 plume evolution.
The formation was found to have an average porosity of 6%, variable permeability distribution, and an average reservoir thickness of about 940 ft. These properties make the Arbuckle saline aquifer an ideal candidate for CO2 sequestration, with ample storage capacity. We discovered significant potential for large-scale CO2 sequestration, owing to the natural fractures in the Arbuckle's lower section, and determined that a single well could feasibly store tens of millions of metric tons of CO2. This capacity could be significantly augmented by increasing the number of injection wells. We observed a positive correlation between the formation's permeability, particularly in the lower Arbuckle, and the volume of CO2 that can be stored. The study confirms the potential feasibility of safe and efficient carbon sequestration in the formation, with potentially minimal risks risking fracture or contamination of underground potable water sources, particularly if CO2 is injected deep in the formation. The less permeable upper Arbuckle, ranging from 0.0001mD to 2.5mD, could offer an additional protective layer. The dominant CO2 trapping mechanism was structural trapping in 3 of 4 simulation cases considered, with an increase in residual trapping at the end of the injection period.
The results of this study can serve as a valuable resource in the potential deployment of CO2 injection in the Arbuckle Group. Moreover, this study could aid decision making during field development in this formation and contribute to efforts to promote a sustainable future.
Laboratory Evaluation of Reversibility Feature of Physico-Chemical Water Shut-Off Agent for Enhanced Gas Recovery
Authors: Sergeev V. , Abe M. 
Published: October 2023

Abstract
A paper presents laboratory research conducted to evaluate technological properties of the nanoparticle-induced water shut-off agent and to assess its potential for gas recovery enhancement in geo-physically complicated reservoir conditions. The studied water shut-off agent is an inverse emulsion generated through the synergy of physico-chemical reactions between natural and artificial surfactants with silicon dioxide nanoparticles (NPs). Ultra-hydrophobicity and stability of the nanoparticle-based emulsion (nano-emulsion) conveys game-changing technological properties, resulting in a high performance of the water shut-off agent. Introduced in this paper research program was specifically developed to meet an inquiry of gas-condensate fields operator for an efficient physico-chemical or chemical water shut-off technology with zero secondary damage to reservoir. Therefore, the research program aimed to evaluate technological properties of the emulsion system with nanoparticles (ESN) in the tight sandstone formation conditions 8990 psi and 230°F. Firstly, rheometric study and tests in an autoclave were conducted to measure rheology, stability, compatibility and floating property of the ESN water shut-off agent under heavier polymer-clay fluid. Secondly, core flooding tests were conducted on four sets of natural low-permeable sandstone core columns to assess reversibility feature of the ESN water shut-off agent and a threshold pressure of the gas-condensate breakthrough. Rheology of the investigated water shut-off agent characterized by the share thinning behavior, i.e., viscosity drops under rise of the share rate and the other way around. The pseudoplastic behavior of the ESN perfectly suits applications in gas wells because it improves processes of preparing and pumping the water shut-off fluid downhole, does not float under heavier process fluids and self-controllable in-situ. It was learned that the ESN is compatible with reservoir and process fluids, and stable at reservoir conditions 230°F and 8990 psi. The ESN's blockage reversibility feature was confirmed in core floods. Overall, the research results confirmed innovative properties of the ESN water shut-off technology with its wide-range compatibility and high stability properties.
Best Practices of Flowback and Deliverability Analysis in the Canadian Unconventional Montney for Enhanced Treatment Stage Design and Reservoir Characterization
Authors: Virues Claudio , Robertson Alexandra , Sendecki Bruce 
Published: October 2023

Abstract
In September 2021, the Alberta Energy Regulator (AER) through a new pressure and deliverability testing directive issued new guidance for inline testing to align with the current practice for conducting these tests. Best practices of these techniques are presented for calculations for industry-submitted inline testing for flowback analysis and industry-submitted Absolute Open Flow deliverability analysis. Results are compared to previously published best practices in the Canadian Unconventional Montney.
The new approach is based on obtaining dynamic fracture dimensions such as fracture half-length and height, conductivity, associated matrix permeability, and well productivity index estimates. This information is supporting evaluation on reserves and near wellbore communication. Analytical and numerical method descriptions are provided that has proven to have significant implications for treatment stage design and reservoir characterization. Complete governing equations are provided and flowback and deliverability techniques are described in detail to permit readers to replicate all results.
80 field case studies are presented for multi-stage hydraulic fractured horizontal wells in the Canadian Unconventional Montney. Comparisons are also provided for Inline testing and deliverability- derived productivity index. The most significant new findings are the variability of fracture dimensions, conductivity, matrix permeability and productivity index impacting reservoir characterization. This is important for well spacing and bench-related reserves assessment at the pad level. For AER it also means an enhancement on reserves assessment of the Montney for its flagship report ST-98 by conducting Rate Transient Analysis (RTA) using rate and bottom-hole pressure information. The findings have direct practical implications for operators in the Canadian Montney shale play and analogous shale plays in USA and elsewhere. Accurate production and pressure data is needed for calculating linear flow parameters, effective surface area, fracture length / height and for optimizing well spacing and frac design. It could be used for input for Rate Transient Analysis (RTA) for resources / reserves assessments in similar unconventional plays.
The novelty of the new approach is in the ability to develop best practices in inline testing and analysis in the Canadian unconventional Montney, focus of significant short-term investment impacting royalties and solve non-uniqueness and/or uncertainty for well testing / completions/ production / reserves in reasonable time using the newly aligned engineering processes.
Importance of Thermal Modelling in CO2 Storage
Authors: Chidambaram P. , Yakup M. H. , Mohd Ali S. , Tewari R. D. , Tan C. , Tiwari P. K. , Das D. P. , Widyanita A. 
Published: October 2023

Abstract
Carbon dioxide sequestration in geological formations involves injection of carbon dioxide (CO2) into a reservoir. Irrespective of the phase of injected CO2 at the well head, there will be a change in temperature of CO2 as it travels from wellhead all the way up to its final storage destination in the reservoir. Such temperature changes affect the fracture gradient of the reservoir and the caprock. Thus, changing the maximum allowable injection pressure and consequently changing the storage capacity of the reservoir. Understanding and accounting for temperature changes is critical in providing a robust estimate of CO2 storage capacity.
A depleted gas reservoir in Central Luconia field, located offshore Sarawak, was evaluated for future CO2 storage. Conventional dynamic modelling is typically isothermal, since it is assumed that reservoir temperature changes during production are minimal and its impact on rock and fluid properties is negligible. But, during CO2 sequestration in geological reservoirs, there could be significant change in temperature of injected CO2 starting from wellhead all the way to the final storage location within the reservoir. Some of the reasons for change in temperature of injected CO2 are a) temperature difference between reservoir and injected CO2; b) geothermal effects as CO2 travels in the wellbore from wellhead to bottom of wellbore; c) Joule-Thompson effect when injected CO2 expands as it enters the reservoir; d) geothermal effects as CO2 migrates through the reservoir to its final storage location. These temperature changes are significant enough to affect the rock and fluid properties. Thus, altering fracture pressure and seal strength. Hence thermal modelling that accounts for changes in temperature has been utilized to estimate storage capacity and CO2 plume migration in the reservoir.
Thermal modelling results show significant cooling near wellbore and all the way up to caprock vertically above injection point. A temperature change of up to ~150 °F has been observed near wellbore and a temperature change of up to ~70 °F has been observed at the caprock. The temperature remains mostly unchanged as we move away from the injector. But the temperature changes observed near caprock directly above injection point is important since this reduces the caprock fracture gradient by as much as ~700 psi. This has a significant impact on storage capacity due to reduction in caprock injection pressure limit. Storage capacity from the thermal model is lower by as much as 10% compared to storage capacity from isothermal model.
Tailored Metal Oxide Nanoparticles-Based Fluids in Acid Restimulation Treatments Reverses Long-Term Hydrocarbon Decline: A Pilot Study in Wolfcamp (A) Formation
Authors: Dalamarinis P. , Radwan A. , Ramanathan R. , Ellafi Abdulaziz , Khanal Suman 
Published: October 2023

Abstract
Multi-fracture horizontal wells suffer from high hydrocarbon decline and water-cuts after initial flow back. This behavior is in part because of near/far field-fracture conductivity damage. Re-fracturing operations (acid or proppant) can mitigate these problems yielding a good cleanout performance and stable oil recovery trends. This paper details a successful pilot to improve long-term well performance using acid stimulation aided by a pioneering tailored metal oxide (TMO) nanoparticles-based fluid in Wolfcamp (A) formation.
Seven wells (in two different areas) with similar designs, same geological landing zone, located within 1 mile from each other were selected to be re-stimulated with different surfactant blends. These wells were producing an average of 4,500 bwpd at a 96% water cut. Acid stimulation programs with a total treatment volume of about 2,000 barrels was designed to stimulate each well. Regular surfactant was added to the treatment fluid in 5 wells, while 2 wells implemented the TMO Nanofluid. The TMO Nanofluid had previously been shown to improve production rates and reduce water cuts with specific focus on long-term performance.
Water cuts, gas-oil ratios (GOR), and hydrocarbon decline rates were monitored daily to observe any significant differences between the well production behaviors. The surfactant-injected wells demonstrated an average of 40% production decline in the 1st six months. The TMO Nanofluid-injected wells showed a reverse trend with a production decline of 5% in the 1st month followed by a production improvement of 10% in the 2nd month and less than 10% production decline after 6 months. This type of behavior is consistent with previous field experiences with the TMO Nanofluid where the production improvement had been sustained over time. The water cut in all wells decreased to about 96%. The TMO Nanofluid worked by providing a unique long-term wettability alteration, reducing the interfacial tension, allowing the chemicals to be retained in the fracture/reservoir phase. It also functions to remove near-wellbore organic formation damage via the structural disjoining mechanism. Overall, this results in better stimulated wells for long-term performance.
The unique characteristics of the TMO Nanofluid in acid stimulation treatments can help restore well/reservoir conductivity and remove near-wellbore formation damage, resulting in improved long-term performance characteristics and improved production decline rates.