bluuebunny/crossref_metadata_2025_split huggingface dataset:
New Approach for Stress-Dependent Permeability and Porosity Response in the Bakken Formation
Authors: Ouadi Habib , Mellal Ilyes , Chemmakh Abderraouf , Djezzar Sofiane , Boualam Aldjia , Merzoug Ahmed , Laalam Aimen , Mouedden Nadia , Khetib Youcef , Rasouli Vamegh , Tomomewo Olusegun 
Published: September 2022

Abstract
During the reservoir depletion and injection operations, the net effective stress is disrupted due to pore pressure changes. As a result, the reservoir properties, mainly porosity and permeability, are influenced by the change in the stress behavior in the reservoir rock. Understanding the porosity and permeability stress-dependent alteration is crucial since it directly impacts the reservoir storage capacity and the production/injection capabilities. Conventionally, lab experiments are conducted to understand the stress dependency of porosity and permeability magnitudes. Two methods are usually used: the unsteady-state method (Core Measurement System, CMS-300) and the steady-state method (Core Measurement System, CPMS). The challenges with these experiments reside in the fact that they are expensive and time-consuming and may cause the destruction of the core samples due to the applied stresses.
This study aims to investigate the effect of stress variations on porosity and permeability changes. These properties were measured on a total of 2150 core data from the three members of the unconventional Bakken formation (upper, middle, and lower), applying 35 different Net Confining Stress (NCS) values, ranging from 400psi to 5800psi. A correlation was formulated between permeability and the NCS to illustrate the stress dependency relationships. The Grey Wolf Optimization algorithm (GWO) was used to tune the correlation for the Bakken formation. Machine Learning methods were also applied for the porosity and permeability stress dependency response prediction, which are as follows: Linear Regression (LR), Random Forest Regression (RF), XGBoost Regression (XGB), and Artificial Neural Network (ANN).
The results demonstrate that the porosity and the permeability decrease with the increase of the NCS and vice versa. The permeability is highly sensitive to the NCS changes compared to the porosity. The developed correlations showed a good fit with the data extracted from the laboratory experiments of the pilot well. For the data-driven models, the coefficient of correlation R2-Score ranged from 91% to 93%.
These models can be used to constrain the modeling work and reduce the uncertainties by introducing the effect of the net effective stress changes during reservoir depletion/injection on petrophysical properties.
Low Resistivity Reservoir Identification of Gumai Formation Using Weighted Scoring Method in West Benakat, South Sumatra Basin, Indonesia
Authors: Permana Aziz , Naiola Mateos , Siregar Daniel , Damuar Syaiful , Suseno Pambudi , Parsaulian Sakti , Siki Dirsya , Barustan Ilham 
Published: September 2022

Abstract
The mature oil field of West Benakat is located in the South Sumatra Basin, one of the most hydrocarbon prolific Indonesian tertiary back-arc basins in Indonesia. Since its discovery in 1933, West Benakat Field has been operating and producing oil for nearly nine decades from Talang Akar Formation (TAF) as the main sand reservoir target with good porosity and permeability. Recently, Talang Akar reservoirs have been depleted through massive development programs, whereas more than 290 wells have been drilled for exploration, production, and injection wells. Decreasing oil production pushes the company's need for an alternative method that can increase oil production through subsurface evaluation in West Benakat Field to find the upside potential besides Talang Akar. One of the best alternative ways focused on the low resistivity pay zone from Gumai Formation (GUF) and Air Benakat Formation (ABF). The qualitative analysis through several well log data in Gumai Formation confirms the potential of low resistivity shaly sand reservoirs, GUF-1, GUF-2, and GUF-3, with neutron-density crossover. However, Talang Akar sand has an average resistivity value equally above 10 ohms. The low resistivity reservoir in Gumai turbidite deep marine sand could be occurred because of high shale content, fine grain sand, and the presence of laminated conductive clay minerals, such as glauconite. However, a low resistivity reservoir was initially considered unattractive because many major reservoirs which contain hydrocarbon would have a high resistivity value. Generally, the conventional petrophysical approach for low resistivity reservoirs in Gumai or Air Benakat Sand could lead to bias and pessimistic interpretation, yet in some cases, rocks with low resistivity have the potential to become hydrocarbon reservoirs. This study discusses how to identify and evaluate low resistivity pay zones and the success story of proving the Gumai hydrocarbon potential in West Benakat Field, South Sumatra.
Continuous Monitoring of Drilling Mud Properties Through Novel Microwave Apparatus
Authors: Alvarez Jose Oliverio , Santra Ashok 
Published: September 2022

Abstract
During drilling operations, encountering highly pressurized brine zones or low-pressure zones can alter the amount of brine in an oil-based mud, also known as oil-brine-ratio (OBR). Thus, monitoring the OBR is an important measurement to determine any changes in the formation pressure.
A non-intrusive microwave drilling mud analyzer (MDMA) for real-time oil-brine-ratio measurements was designed, built, and tested on drilling muds performed. The MDMA uses a vector network analyzer to measure the reflection (S11) and transmission (S21) spectra of drilling muds. The initial design concept consisted of a pair of waveguides whose ends face each other and are placed on the inner surface of the pipe. The waveguides have a diameter similar to the main pipe and are filled with specific low loss materials with dielectric value near that of the fluid in the pipe. Based on the initial design, an optimized prototype was designed and built. The improved design increases bandwidth by adding tapered ridges to the original cylindrical waveguide and optimizes the feed details to maintain an impedance match to the feed connectors.
Results on drilling muds shows a high sensitivity to brine content, which can be inverted to have high accuracy OBR values. In addition, the MDMA showed also high sensitivity to water dilution and to an increase in solids content
Real-Time Well Performance Measurement Using Non-Intrusive Clamp-On Measurement Technique
Authors: Black Michael , Heinks Carsten , Cramer Ron 
Published: September 2022

Abstract
The ability to quantify well performance individually and real-time across most if not all wells in a given field is a capability that bridges the gap between production and reservoir management. Having real-time oil, gas and water flow measurements from each well distributed across a reservoir has the potential to enable significant improvements in data driven and scalable production/reservoir surveillance and optimization. Traditionally, test separators offer the ability to perform well testing but the process is discontinuous, relatively infrequent and labor intensive. Over the last few decades in-line multiphase meters (many using radioactive sources) were developed which offer the possibility of real-time measurement but have high installation and ownership costs.
To enable cost effective, continuous well/reservoir management with minimal/zero well tests, we have devised a new type of clamp-on non-radioactive multiphase measurement system for rapid installation on the flowlines of new wells, or retrofitted to existing and producing wells with zero intervention. We will present hydrocarbon flow loop results obtained with this system – field measurement campaigns are in progress and preliminary data shows good read across between field and flow loop measurements.
A clamp-on multiphase flowmeter measurement system based on a combination of electromagnetic acoustic transducer (EMAT) and guided ultrasonic waves was developed to continuously measure liquid flow, gas flow and water-liquid ratio. A multiphase flow loop was constructed to simulate well multiphase flow conditions. The results obtained from the multiphase flowmeter system and the simulated flow patterns were validated using a combination of flow loop reference sensors and optical measurement of the liquid flow patterns using a high-speed camera. In parallel with these activities, a field based measurement campaign has also been initiated using a ruggedized portable measurement system.
Results from this activity shall be presented, demonstrating adequate performance levels for production applications. Work to progress field measurements to establish system performance under live measurement conditions is ongoing.
The measurement technique described in this paper is a novel approach towards the assessment of well performance not previously implemented. Additionally, the system capability (zero intervention combined with the ability to retrofit) opens up opportunities towards data driven scalable production/reservoir optimization not available with previous technologies.
Feasibility Study of Recrosslinkable Preformed Particle Gels for Natural Gas Injection Profile Control
Authors: Al Brahim Ali , Eriyagama Yugandhara , Bai Baojun , Schuman Thomas 
Published: September 2022

Abstract
Recrosslinkable Preformed Particle Gel (RPPG), a novel preformed particle gel of which particles can bond together to form a strong bulk gel system after being placed inside the target formation, has been successfully applied to control conformance problems for water flooding projects. However, no research has been conducted about whether RPPG is feasible in improving gas flooding performance in mature reservoirs. The study presents a systematic evaluation of acrylamide (AM) and 2-acrylamide-2-methylpropane sulfonate acid (AMPS) based RPPG including phase stability under different gel-gas kinetics and plugging performance to natural gas and water. Different experimental apparatuses were designed to quantify and visualize the RPPG phase stability under static and dynamic gel-gas interactions. The RPPG phase stability was evaluated under a different range of injection pressure, gas exposure time and swelling ratio. Also, the RPPG stability was compared to the in-situ gel system HPAM/Cr (III) which has been applied in oilfields to control gas injection conformance. The RPPG plugging efficiency was evaluated using open fractured cores with different apertures. The results showed that the RPPG was stable under both static and dynamic gel-natural gas interactions and was stable when being exposed to an acidic environment with an insignificant total percentage weight loss (&lt; 3%). Additionally, the strength of the RPPG was further improved with the longevity of the gas exposure. Furthermore, different from the in-situ gel system HPAM/Cr(III), which exhibited high degree of dehydration under natural gas and exhibited substantial syneresis under acidic conditions, the microstructure of the RPPG remained stable after the dynamic gas exposure. The results of the coreflooding experiments demonstrated that the RPPG had excellent plugging efficiency, which was closely related to the swelling ratio and the fracture aperture. This is the first study where a polymer gel system has been systematically assessed through varied testing methodologies using natural gas as opposed to other studies where Nitrogen was used to simulate natural gas behavior. The robustness of the RPPG system makes it a viable candidate for improving the gas flooding processes in mature reservoirs dominated by conformance problems such as void space conduits, fractures, and high permeability channels.
Success Using Quartz-Based Technology in Rigless Mechanical Integrity Tests in the DJ Basin
Authors: Howley Grace , Winegarden Jason , Petrie Paul , Michel Cody , Algadi Otman , Drevdal Kjell Erik , Rygg Vidar 
Published: September 2022

Abstract
When a well is shut in for an extended period, the mechanical integrity of the production casing must be verified periodically to ensure there are no leaks in the casing that could lead to potential fluid migration between the producing zone and other formations along the wellbore. Traditionally, these mechanical integrity tests involve moving in a workover rig, tripping production tubing out of the well, setting a mechanical bridge plug above the highest set of perforations, and then pressure testing the casing. This operation is very time- and labor-intensive, with significant safety exposure risks for personnel involved. This paper describes work performed on 83 wells in the DJ Basin where an alternative method, not requiring a workover rig, was used.
In this case, conventional cementing equipment was used to pump a Bingham-plastic nonconsolidating sealing material with a high-solid-volume fraction through the tubing to the perforations. This sealing material is a high-quality, quartz-based slurry using an engineered particle-size distribution (PSD) from &lt;100 nm to 2 mm. The specific PSD of the solids in this slurry is designed to maintain pumpability and ensure near-zero permeability once the slurry is in place. The sealing material creates an impermeable barrier across the perforations, which enables the casing to be pressure tested. The operational simplicity of this material offers improvements to both operational efficiency and safety risks. This slurry also poses little to no risk to the environment from an accidental spill or exposure, as it is a purely natural, silica-based product.
The silica-based slurry performed successfully, and the resulting mechanical integrity tests were equally successful. This paper explains the state regulations surrounding the mechanical integrity test, a comparison of the advantages seen with the alternative method, a detailed description of the job execution, and a summary of results observed in the cases where this alternate method was used.
Uncertainty and Sensitivity Analysis of Multi-Phase Flow in Fractured Rocks: A Pore-To-Field Scale Investigation
Authors: He Xupeng , Zhang Zhen , AlSinan Marwah , Li Yiteng , Kwak Hyung , Hoteit Hussein 
Published: September 2022

Abstract
Despite recent advancements in computational methods, it is still challenging to properly model fracture properties, such as relative permeability and hydraulic aperture, at the field scale. The challenge is in determining the most representative fracture properties, concluded from multi-scale data. In this study, we demonstrate how to capture fracture properties at the field scale from core-scale and pore-scale data through multi-scale uncertainty quantification, and assess how pore-scale processes can significantly impact the recovery factor. There are three components within our workflow: 1) performing high-resolution Navier-Stokes (NS) simulation at pore-scale to obtain hydraulic aperture of discrete single fractures, 2) embedding pore-scale parameters into core-scale for predicting field-scale objective, such as recovery factor, and 3) performing Monte Carlo simulations to determine the relationship effect of the pore-scale parameters to the field scale responding. At pore-scale, we start with four parameters that characterize the fractures: mean aperture, relative roughness, tortuosity, and the ratio of minimum to mean apertures. We then construct hydraulic aperture surrogates using an Artificial Neural Network (ANN). At the field scale, we deploy Long Short-Term Memory (LSTM) to capture the recovery factor at field-scale. The final results are the time-varying recovery factor and its sensitivity analysis. Monte Carlo simulation is performed on the final surrogate to produce the recovery factor value for various time-step. The result is beneficial for risk assessment and decision-making during the development of fractured reservoirs. Our method is the first to quantitatively estimate multi-scale parameters’ effect on recovery factors in two-phase flow in fractured media. This method also shows how we accommodate and deal with multi-scale parameters.
Well Control Considerations for CO2 Wells Based on Multiphase Flow Simulations
Authors: Zhou Lei , Anfinsen Bjoern-Tore , Hashemian Yahya , Yuan Zhaoguang , Mosti Inge 
Published: September 2022

Abstract
CCUS (Carbon Capture Utilization and Storage) is expected to be an important contributor to the ambition of reaching a net zero objective. Drilling and workover of wells to be used as CO2 injectors, pose a well control risk that needs to be properly understood and minimized.
The paper will address the significant differences between CO2 wells and traditional hydrocarbon wells. Due to differences in phase behavior, both well design and operational procedures would be impacted and needs to be revised. Traditional well control procedures are not necessarily applicable in CCUS wells without modifications.
A generic well was used to study the differences between a CO2 well and a hydrocarbon (methane) well with respect to design and procedural changes in case of a well control incident. A well control simulator capable of transient multiphase modeling of hydrocarbon and CO2 systems was used to evaluate the differences. Important operational and design limiting factors like volume, pressure and temperature responses, hydrate formation, phase transition as well as mitigation strategies and contingencies were evaluated. The model showed that with both SOBM and WBM, the CO2 influx entered the well in its supercritical form. Under static conditions, the CO2 remained in its supercritical form and showed no migration in SOBM, making its detection more challenging than for a methane influx. Driller's method was applied while simulating circulating the CO2 influx. For both mud types, the model showed greater liquid velocities compared to methane, which would reduce the time to react and put greater demands on surface equipment. The model also showed a greater drop in temperature than for a methane influx. Due to J-T cooling effect, the model shows that supercritical CO2 expansion near the surface can lead to significant temperature reduction, which in turn can lead to formation of hydrates and block the circulation. This effect also needs to be considered in the well design as the physical properties of the casings and surface pipes can be changed due to variation in temperature. Based on these results, measures to mitigate CO2 well control risks are discussed. This study will provide new knowledge regarding well control incidents related to CO2 wells. Improved understanding can be used to optimize operational procedures and potentially lead to new mitigation techniques.
Geological Neural Network Methodology for Automatic History Match; Real Case for Rubiales Field
Authors: Rodriguez-Torrado Ruben , Pumar-Jimenez Alberto , Ruiz-Mataran Pablo , Sarabian Mohammad , Togelius Julian , Toro Agudelo Leonardo , Rueda Alexander , Gallardo Enrique , Naranjo Ana Maria , Arango Sandro , Villasmil Jose Alberto 
Published: September 2022

Abstract
Full history match models in subsurface systems are challenging due to the large number of reservoir simulations required, and the need to preserve geological realism in matched models. This drawback increases significantly in big real fields due to the high heterogeneity of the geological models, the reservoir simulation computational time (which increases superlinearly). In this work, we propose a novel framework based on artificial intelligence to address these shortcomings. Our workflow is based on two main components: The first is the new combination of model order reduction techniques (e.g., principle component analysis (PCA), kernel-PCA (k-PCA)) and artificial intelligence for parameterizing complex three-dimensional (3D) geomodels, called "Geo-Net". Our new approach is able to create complex high dimensional heterogeneous reservoirs in seconds, providing better correspondence with the underlying geomodels, hard-data constraints and geological plausibility. The second component is a derivative-free optimization framework to complete the automatic history matching (AHM). This new approach allows us to perform local changes in the reservoir at the same time as we conserve geological plausibility. We have examined our methodology in a real field in Colombia. The Rubiales Oil Field is located in the Llanos Basin with original oil in place of around 6 billion barrels. The key finding here is that the Geo-Net is able to recreate the full geological workflow obtaining the same high order of statistics as traditional geo-statistical techniques. Nonetheless, our Geo-Net allows us to control the full process with a low-dimensional vector and reproduces the full geological workflow 10,000 times faster than commercial geo-statistical packages. Finally, the full optimization workflow has been applied to AHM. Results show an improvement with respect to best practice of traditional history match workflows.
The Reversible Relationship Between Choke Management and Liquid Yield Trends in Shale Reservoirs
Authors: Barzin Yalda , Walker Gregory 
Published: September 2022

Abstract
This paper builds on the observed strong correlation between liquid yield (Condensate Gas Ratio) profiles and choke management in the gas condensate wells, described in URTeC 3722999.
The study has included production profiles of over a hundred wells (initial CGR ranging from 50 to 250 STB/MMscf) operated across both the Eagle Ford and Duvernay.
The condensate yield has been observed to change depending on the choke strategy when the well is operated above the phase envelope. While a stable choke size promotes a stable CGR value, a drawdown strategy that includes rapid choke ramp-ups has a corresponding variation in CGR even above the saturation point.
What is explored in this paper is that the change in CGR is reversible, where a reduction in choke size will cause the system to restore to a higher CGR without damage to the well. A more conventional system would expect that a reduction in CGR results in liquid dropping out and potentially causing relative permeability issues (condensate banking). The reversibility is consistent with the adsorbed gas hypothesis (SPE 185045), where the change in CGR is attributed to contribution of desorped dry gas, rather than liquid drop out.
The second part of the paper investigates the relationship between small changes in choke and the corresponding change in liquid yield. The initial work had been looking at plots of logarithmic scaled axis for liquid yield and linear scale on choke, but closer examination has shown that the trend is more of a linear response. If the underlying mechanism is adsorbed gas, then the trend would be expected to have at least a qualitative response to a proxy for adsorbed gas such as TOC.