bluuebunny/crossref_metadata_2025_split huggingface dataset:
Modeling Heterogeneity of Glacial Reservoir Using Geostatistical Approach: A Case Study, Southwest Libya
Authors: Bergigh F. A. , Meddaugh W. S. , Alkhemri T. M. 
Published: October 2023

Abstract
The main challenge of modeling the glacial sandstone deposits is capturing the property pattern in the reservoir, because of the abrupt changes from one depositional environment to another. This reservoir heterogeneity impacts the infill well planning and production performance of the field. In this research, a comprehensive workflow is presented to model the spatial distribution of porosity and permeability within the Mamuniyat sandstone in the Murzuq Basin, Onshore Libya, using geostatistical techniques. Geostatistical techniques in combination with the available information from six wells using geological information, petrophysical analysis, and seismic interpretation were used to construct a 3D model for the reservoir. The structural input included the main interpreted horizons, with a total of 34 faults. Six facies were identified in the reservoir, dominated mainly by the Outwash Fan and Submarine Channel. To categorize reservoir quality, four rock types were defined based on the observed relationship between porosity and permeability. Variogram analysis was performed to describe the spatial relationship between all reservoir layers. Sequential Gaussian Simulation was utilized for porosity modeling and Gaussian Random Function Simulation for Permeability were both constrained to facies. Water saturation was modeled based on the height function method for each rock type. The final model revealed significant variation in reservoir characteristics; this variability is attributed to the diagenetic process that affects the reservoir quality of the sandstone. The best reservoir characteristic was encountered in structural highs, where the most productive wells had been drilled in the area. The incorporation of more data such as core analysis, seismic attributes, and the engineering information in the model will be useful to better understanding of reservoir quality, thus improves future development decisions for the field.
Exploration and Practice of Composite Temporary Plugging Fracturing Technology for Deep Shale Gas Horizontal Wells: A Case Study from X2 Well in Southeastern Sichuan
Authors: Hu Zheyu , Zhao Jinzhou , Ren Lan , Lin Ran , Hu Dongfeng , Li Zhenxiang , Lin Chen 
Published: October 2023

Abstract
The deep shale gas formation that has a burial depth of more than 3,500m covers nearly half of the area of entire Wufeng Formation-Longmaxi shale gas formation in the Southeastern Sichuan Basin, and more than 50% of the shale gas resources are reserved in this burial depth range. Deep shale gas is buried deep with high temperatures, high formation stress, and strong rock plasticity. It is difficult to form and maintain a complex fracture network underground. The deep shale gas fracturing technology is important to promote the overall development of shale gas in the Sichuan Basin. Well X2 is a pre-exploration well in the Southeastern Sichuan Basin. The maximum vertical depth of this well is 4,343.8 m, the average clay mineral content of the high-quality shale interval is 26.2%, the average siliceous mineral content is 48.1%, the average salt mineral content is 14.9%, the elastic modulus is 45.6 GPa, and the maximum and minimum horizontal principal stress of the reservoir is 115.5 MPa and 98 MPa, respectively. Then the horizontal stress difference is 16.8~18.5 MPa. The reservoir is characterized by a high horizontal stress contrast and a low brittleness, which severely restricts the formation of an effective complex fracture network. A composite temporary plugging fracturing of inner-fracture + inlet fracture is proposed, and the fracture net pressure is increased to improve the fracture network complexity and balance the propagation of multiple fractures by adjusting the inlet flow rate of each fracture to achieve high-efficiency fracturing. The 1,503 m horizontal well interval is hydraulic fractured 30 stages with 3 clusters in each stage, cluster spacing is 8~10 m, and the average stage length is 47.33 m. The total injected fracturing fluid volume is 89,736.6 m3 (fluid strength 63.19 m3/m), and the total amount of proppant injected was 3,477 m3 (sand strength 2.45 m3/m). The average overall sand-fluid ratio is 3.88%, the pump rate is 14~18 m3/min, and the daily test production of this fractured deep shale well reached to 41.2×104 m3. The fracturing performance is remarkable. We proposed a deep shale gas fracturing technology with "more stage & less cluster, dense cluster perforation, large fluid volume, high pump rate, medium proppants amount, double plugging, and variable viscosity slippery water alternating injection". It makes an exploration breakthrough of the deep shale gas buried more than 4,000 m and promotes the development of deep shale gas fracturing technology in China.
Flowing Bottomhole Pressure During Gas Lift in Unconventional Oil Wells
Authors: Jin Miao , Emami-Meybodi Hamid , Ahmadi Mohammad 
Published: October 2023

Abstract
We present artificial neural network (ANN) models for predicting flowing bottomhole pressure (FBHP) of unconventional oil wells under gas-lift operations. Well parameters, fluid properties, production/injection data, and bottomhole gauge pressures from 16 shale oil wells in Permian Basin, Texas, are analyzed to determine key parameters affecting FBHP during the gas-lift operation. For the reservoir fluid properties, several PVT models, such as Benedict-Webb-Rubin, Lee, Gonzalez, & Eakin, and Standing, among others, are examined against experimentally tuned fluid properties, i.e., viscosity, formation volume factor, and solution gas-oil ratio, to identify representative fluid (PVT) models for oil and gas properties. Pipe flow models, i.e., Hagedorn & Brown, Grey, Begs & Brill, and Petalas & Aziz, are also examined by comparing calculated FBHP against the bottomhole gauge pressures to identify a representative pipe flow model. Training and test data sets are then generated using the representative PVT and pipe flow models to develop a physics-based ANN model. The physics-based ANN model inputs are hydrocarbon fluid properties, liquid flowrate (qL), gas-liquid-ratio (GLR), water- oil-ratio (WOR), well depth (TVD), wellhead pressure (Pwh), wellhead temperature (Twh), and temperature gradient (dT/dh). A data- based ANN model is also developed based on only TVD, Pwh, qL, GLR, and WOR. Both physics- and data-based ANN models are trained through hyperparameter optimization using genetic algorithm and K-fold validation and then tested against the gauge FBHP. The results reveal that both models perform well with the FBHP prediction from field data with a normalized mean absolute error (NMAE) of around 10%. However, a comparison between results from the physics- and data-based ANN models shows that the physics- based model accuracy is higher at the later phase of the gas-lift operation when the steady state pipe flow is well established. On the other hand, the data-based model performs better for the early phase of gas-lift operation when transient flow behavior is dominant. Developed ANN models and workflows can be applied to optimize gas-lift operations under different fluid and well conditions.
Engineered Materials and Machine Learning for Carbon Storage Well Integrity
Authors: Pollock Jacob , Elshahawi Hani 
Published: October 2023

Abstract
Carbon capture and sequestration is an effective short-to-medium term option for reducing net carbon emissions into the atmosphere. The prevention, monitoring, and prediction of carbon dioxide leakage points and pathways are critical to the success of carbon capture and sequestration. The success of carbon dioxide injection operations and the endurance of long-term storage are partially dependent on well design and the materials used for well construction. We have developed a stack of technologies which enable enhanced well robustness, monitoring of carbon storage facilities, and modeling of their performance. They improve well integrity through better cement bonding with the casing pipe and enhanced measurement of cement condition and additionally provide critical information for intervention and remediation.
Nanocomposite surface treatments improve cement-to-casing bonding, reduce channeling, and prevent annular fluid migration while acoustically responsive metamaterial cements enable monitoring cement integrity, mechanical load, and chemical environment. The materials are sufficiently robust thermally, chemically, and mechanically for use in carbon storage wells and other types of downhole construction or remediation operations. The composite cement materials possess unique acoustic signatures that allow their distinct detection as well as measurement of local chemical and mechanical conditions.
The acoustic and physical properties of these novel materials were characterized in the laboratory as well as field trials. The improved acoustic contrast provided by these technologies enhanced log analysis and substantially improved discernment of cement location and mechanical loading. Machine learning was used to quickly identify cement and reservoir condition based on acoustic signals and to interpret sensor responses. The combination of these technologies enables the tracking of downhole and subsurface fluid distribution and flow. They can furthermore be used to exploit remaining reservoirs while preventing carbon dioxide plume migration. These metamaterials and nanotechnologies are highly scalable, which has been demonstrated in multiple manufacturing and deployment trials.
Dynamic Characterization of Pore Structures in Hydrate-Bearing Sediments During Hydrate Phase Transition
Authors: Chen Mingqiang , Li Qingping , Zhou Shouwei , Pang Weixin , Lyu Xin , Zhu Junlong , Fu Qiang , Lyu Chaohui , Ge Yang 
Published: October 2023

Abstract
Natural gas hydrate widely distributed in marine sediments and permafrost has brought great attention due to its large reserves. Unlike conventional reservoirs, the effective pore structures vary from time and space due to hydrate dissociation and secondary formation in the development, which produces significant impacts on gas flow and production. Therefore, figuring out the evolution of dynamic pore structures is of great importance for the efficient development of hydrate deposits.
In this work, excess-water hydrate formation method was combined with micro-computed tomography to study hydrate transition effects on the evolution of dynamic pore structures. Gas state equation and chemical reaction dynamics were combined for separating the representative 3D images at different stages of hydrate formation into four phases, which are respectively hydrate, water, gas and solid skeleton. Hydrate pore habit evolution, formation characteristics, spatial distribution heterogeneity and its effect on the effective porosity variation were studied in detail. Afterwards, a modified maximal ball method was employed to extract hydrate-bearing pore networks at different stages of hydrate phase transition. Hydrate phase transition effects on the effective pore and throat radii distributions, pore and throat cross-sections, throat lengths and distance among connected pore bodies, as well as pore topology were further investigated based on the extracted networks.
Results show that hydrate pore habit varies in porous media during hydrate formation with the main pore habit of pore filling mode. Hydrate spatial distribution exhibits some heterogeneity, causing diverse hydrate saturation at different layers during hydrate phase transition. Hydrate disrupted pore integrity to some extent, resulting in more extracted pore bodies and throats with increased hydrate saturation. In addition, hydrate phase transition reduces pore-throat radii and distribution regularity to different degrees, and results in more irregular pore-throat morphology, decrease of throat length and distance among connected pore bodies as well as poorer connectivity at the same time. This study provides a novel insight in better understanding the evolution of dynamic pore structures and lays a good foundation for the effective development of natural gas hydrate deposits.
Extended Aquifer System Pressure Behavior Under Carbon Storage
Authors: Mukhtar Muhammad Haseeb , Hatzignatiou Dimitrios Georgios , Ehlig-Economides Christine 
Published: October 2023

Abstract
Most reported carbon storage projects have involved inexpensive CO2 capture from gas processing plants or ethanol refineries. However, widespread carbon capture and storage application must avoid any risk that high capital investment cost for carbon capture from stationary point sources leads to unanticipated issues related to the aquifer storage. This paper reviews successful and unsuccessful carbon storage projects and explains simple extended aquifer system fundamentals that must be considered in selecting a storage aquifer.
This study begins by evaluating reported carbon storage projects in the context of an extended aquifer system with specific attention to initial formation pore pressure and potential or known hydraulic vertical or lateral communication with hydrocarbon accumulations and/or fresh water. Further study focusses on how the contrast between injection well and aquifer pressure evolution enables understanding of the overall aquifer material balance. Finally, we consider implications of brine migration during and after long term CO2 injection in unconfined aquifers.
Experience in the petroleum industry with aquifer behavior include presence or lack of water influx and production from hydrocarbon reservoirs that share a common aquifer. Of particular importance is the observation that hydrostatic initial formation pressure indicates the possibility that a petroleum system, or an extended aquifer system without hydrocarbon accumulation(s), connects to atmospheric pressure through an unconfined aquifer. In such cases indefinite injection will never increase the regional aquifer pressure. Further, initial formation pressure that exceeds hydrostatic pressure implies a petroleum system or an extended aquifer system that is volumetrically limited. In such cases injection will increase the system pressure, and pressure monitoring can detect leakage from the system. Finally, CO2 injection into an aquifer will displace brine in the direction of lower pressure that could relate to distant production from the same aquifer or from hydrocarbon reservoirs with which it communicates.
Reasons for known carbon storage project interruptions have included unexpected lateral plume migration or aquifer pressure increase during CO2 injection that might have been anticipated with attention to straightforward consideration of aquifer enabled hydraulic communication. Such extended aquifer dynamics must be included in long term models for permanent CO2 storage during and after injection.
Downhole Electric Heating to Maintain Wellbore Temperature Above the Wax Appearance Temperature
Authors: JIM SHEN , ERIC KLOTZ , ROD EWACHA 
Published: October 2023

Abstract
Optimizing Waxy Oil Production is challenging due to paraffin deposition. Crystallization of waxes in crude oils leads to non-Newtonian flow characteristics as described by Zheng et al in SPE paper OTC-26914 (Zheng, 2006). This crystallization may cause complete blockage of tubing and other flowlines by wax. These problems will lead to decreased flowrates and well intervention. Shutting in a well for workover increases the operation cost. The most common intervention to remove paraffin deposits is hot oiling and chemical injection. When comparing an alternative of circulating hot oiling down the annulus to melt paraffin or chemical injection; downhole heater is a good option. Downhole heating allows operators to maintain production by increasing the tubing temperature above the paraffin precipitation point. Stabilized reservoir inflow, reduced pump intake pressure and potentially dangerous and expensive hot oil and chemical batch interventions can be avoided. The aforementioned was achieved in a Provost Alberta waxy oil well with the resultant completion described and the field data recorded.
Sedimentary Analysis Via Automatic Image Segmentation and Clustering with the LWD OBM Resistivity Image: A Case Study from Gulf of Mexico
Authors: Yang S. , Wang Y. , Shrivastava C. 
Published: October 2023

Abstract
Microfacies analysis is the first step for depositional environment interpretation and sand body prediction. Textural details from borehole images are building blocks for facies analysis, representing different paleo sediimentation conditions. Associated workflows have been applied on high resolution borehole images by geologists and log analysts manually. Automation via machine learning solutions provides an opportunity to improve the working efficiency and accuracy. Such an approach has given satisfactory results with post-drilling wireline images. In this paper, the improved workflow for sedimentary analysis was applied and validated with a logging-while-drilling (LWD) resistivity imager in oil-based mud environment (OBM).
The OBM LWD resistivity image in oil-based mud provides 72 data points at single depth from 4 different frequencies of electromagnetic measurements with a patented processing. The non-gap resistivity image gives more confident texture characterization. The continuous histogram and correlogram derived from image data were used for image segmentation. In each image segmentation, multiple vector properties were extracted from image data representing different texture features including adoptive variogram horizontally. Agglomerative clustering was selected for its stability and repeatability. The internally built dendrogram allows to automatically determine the number of clusters by finding a stable distance between the clusters’ hierarchy branches. In addition to the features extracted from image data, optional petrophysical logs with variable weights may be fed to the algorithm for a better classification.
A case study from Gulf of Mexico is being used to demonstrate this workflow with Hi-Res LWD image. More than 10 different sedimentary geometries were classified automatically from image and petrophysical logs. The microfacies were named manually from sedimentary geometries with the related geological concept accordingly. The fluvial channel and delta sedimentary environment were interpretated finally from microfacies association. The interpretation results were compared and validated with published dips-based solution as well.
This is the first time for the automatic borehole image segmentation with LWD OBM images. The working efficiency was improved a lot through this workflow and the accuracy of microfacies interpretation was guaranteed by machine learning solution.
Quantitative Mapping of Methane Emissions in Oil & Gas Facilities
Authors: Andrews A. Ballard , Boucher Christopher , Chakrabarti Aditi , Dauphin Mathieu , Doshi Manasi , Rashid Kashif , Speck Andrew , van Pelt Aaron , Yuan Junyi , Zielinski Lukasz 
Published: October 2023

Abstract
Methane is an invisible greenhouse gas predicted to account for over 30% of global warming over the next decade. A substantial portion of the methane emissions from oil and gas (O&G) facilities arise from events that are intermittent. Continuous monitoring using methane emissions detectors installed permanently at a site offers a cost-effective way to identify, quantify, and repair intermittent emissions. Due to the wide variety of O&G sites, we have developed two different continuous monitoring solutions for quantitative mapping of methane leaks, i.e., methane point sensors and methane light detection and ranging (LiDAR) cameras. The methane point sensors use proprietary inversion algorithms minimizing false positives and the methane LiDAR cameras offer a unique capability of continuously scanning an entire O&G facility for direct measurement of leak rates. A single blind-study at the Methane Emissions Technology Evaluation Center (METEC) at Colorado State University confirms that both systems perform well at leak detection with methane point sensors being better suited for small to mid-sized simple facilities while the methane LiDAR camera is a better choice for larger and more complex sites. Continuous monitoring of the facilities is possible with both systems using a digital platform to track emissions which aids operators to manage their emissions abatement.
Solved: ESP Shutdowns and Restart Issues—Novel Pump Protection and Active 3D Dispersion System Improve ESP Performance in Multiple Wells
Authors: Bhattacharjee A. , Dikshit A. , Tullier B. , Mouget S. , Tripathi A. , Gupta S. K. 
Published: October 2023

Abstract
In North American land unconventional completions, operators are pushing production limits to keep up with global energy demand. Uninterrupted production with minimal operational expenditures is vital to deliver a quicker return on investment, and electrical submersible pump (ESP) performance plays a critical role. Aggressive production, inadequate wellbore cleanouts, and corrosive production fluid can result in unplanned shutdowns, restart issues, and the erosion of ESP parts. This paper presents a novel pump protection system that enhances ESP run life by significantly improving restarts, actively managing corrosive chemicals, and reducing scale buildup in addition to the design, development, and field installations results.
The system comprises a 3D filter, an intake control valve, a novel 3D chemical dispersion system, and a novel sand fallback protection system (SFPS) above the ESP. This paper focuses on the dispersion system and the SFPS. The 3D chemical dispersion system was developed to counter scale, paraffin, and sulfide deposition over time. This active dispersion system uses a novel injection manifold for effective downhole chemical treatment at the filter level. The SFPS was designed to ensure that the suspended solids on the ESP as a result of a shutdown, planned or unplanned, do not pose a risk to restart. The unique coil-based design vibrates with ESP pressure head, breaks down the sediments, and effectively disperses the solids back into the production fluid.
The pump protection system has been installed successfully in more than 50 wells in North America. The data show that the SFPS has enabled an improvement of more than 6% in the uptime, defined as the ESP run time as a percentage of the well's total operating time. It has also resulted in a 58.9% reduction of the average time required to restart the pump following an ESP stop event. In all of the wells, the new ESP systems are still running and in one case has already exceeded the run life of the previously installed equipment that did not include an SFPS. The number of ESP stop events, particularly those resulting from particle-related overload issues, has decreased significantly, by 75.5%. Furthermore, the average amperage during pump restart has decreased by 32.5%. The use of the active chemical dispersion system ensured that various chemicals were uniformly injected downhole per the well environment, and such wells had lower scale buildup compared to those in which no system was installed. no system was installed.
The novel SFPS and 3D dispersion system have been developed, qualified, and field installed, and the system designs as well as the results from more than 50 field installations are presented. The systems and the methodology are unique in design and have helped several operators in North America improve ESP pump performance and run life.