bluuebunny/crossref_metadata_2025 huggingface dataset:
Local Economic Practices in Developing Islamic Financial Products in Indonesia
Authors: Sofyan Andi Syathir , Yunus Ayu Ruqayyah , Muslihati Muslihati , Anwar Nurfiah , Saidy Emily Nur
Published: May 2023

The culture and geography of a country are the cause of low Islamic financial inclusion and the lack of public knowledge in the Southeast Asian region about the Arabic term on Islamic financial products. Therefore, this study aims to integrate local wisdom and Islamic financial inclusion and realize Islamic -based financial products based on local wisdom. This research is a qualitative descriptive study that is a literature review. The object of the discussion is sourced from research, articles, and reference books related to this topic. The research results are integrating culture with Islamic financial institutions through several efforts, first preaching the Islamic economy with a psychosufistic approach that manifests in the value of Tauhid, humanity, humility, local wisdom and self-transformation to people with low Islamic financial literacy. The second is to strive to create financial products by identifying traditional economic practices throughout Indonesia based on research analyzed by the ‘urf rule. This research has implications for information on the potential market share of Islamic finance in Indonesia and solutions to developing Islamic financial inclusion. The issue of strengthening the market share of Islamic finance in rural areas is still weak. This research study is the first to develop financial products based on local practices in Indonesia.
Improved Model for Predicting the Productivity of Multi-Fractured Shale Wells. TMS and EFS Field Data as Case Studies
Authors: Fadairo Adesina Samson , Egenhoff Sven , Adeyemi Gbadegesin Abiodun , Ling Kegang , Tomomewo Olusegun Stanley , Oladepo Adebowale David , Oni Opeyemi , Nwaokwu Richmond Nduka
Published: May 2023

Multi-fractured horizontal wells have been an admirable completion technique for unconventional resources such as in Tuscaloosa Marine shale (TMS) and Eagle Ford Shale (EFS) plays located in the United States. Studies have shown that the productivity of multi-fractured wells of these two shale plays are majorly based on the fracture conductivity, which may be dependent on the type of the geometrical shape of the fractures connecting the fluid to the well. A reliable model is desirable to the operator to accurately capture the productivity of multi-fractured shale wells. Several mathematical models have been adopted with various assumptions that include simple slot geometry for fracture shape in the derivation of production rate models. These assumptions significantly simplify the existing model's applications but limit the efficiency of the models to accurately predict the fluid production rate.

Failure to utilize an elliptical fracture shape and a correct drive mechanism-based model for analyzing flow rate have been considered as a vital reason for the disparity between the calculated results by the past investigators and the exact values obtained from TMS and EFS field measurements. In this study, an elliptical model based on the fracture geometry has been derived to analyze the productivity of multi-fractured shale wells considering the accurate drive mechanism for the shale play. The model validation has been achieved using field data from the Tuscaloosa Marine shale (TMS) and the Eagle Ford Shale (EFS) plays. The results generated from the newly improved model resulted in more accurate outcomes when compared with results presented by Yang and Guo (2019) and Guo and Schechter (1997); all these authors assumed the cross-sectional area of the induced fractures as being a slot showed nonconformity using real life values from the Tuscaloosa Marine shale (TMS) and the Eagle Ford Shale (EFS) plays as benchmarks. The newly improved model reduces the prediction percentage error to 0.55% and 0.43% compared to the percentage error reported by Yang and Guo (2019) as 9.1% and 3.5% and by Guo and Schechter (1997) respectively as 29.7% and 47.2 % using the actual oilfield results as their benchmark. The accurate prediction of the long-term productivity of multi-fractured oil shale depends on the ability to determine fracture geometry and the drive mechanisms that dominantly control flow in the shale play considered. Sample calculations of flow rate of the two fields considered and the controllable parameters influencing the flow rate have also been identified. The study would serve as a tool for accurate assessment of flow rate in multi-fractured wells of shale plays and analyzes its performance.
The Investigation of Workover Rig Scheduling Optimization Using Genetic Algorithms – Part I
Authors: Popa Andrei , Bloomquist Carl , Marghitoiu Sorin
Published: May 2023

Well intervention for restoring or increasing production is a routine activity in any oilfield, however, it becomes an optimization opportunity for large fields with thousands of wells and high failure rate. Balancing between proactive and reactive workovers to optimize the rig schedule is a complex decision that requires a compelling objective function. Most of the time the decision is driven by economics, which are estimated from the well production potential. But there are other factors that can lead to different drivers or decisions outside of pure economics such as the duration of rig travel, uncertain duration of the job, and the "lost-oil" during the time the well is "down".

The study investigates the application of evolutionary computation techniques, in particular the use of genetic algorithms for the complex task of well workover rig scheduling. It addresses the case of large fields with a high level of activity, sizable number of failures, healthy list of well backlog, and a large number of active workover rigs. This specific scenario is common in large waterflooding and heavy oil fields.

The research explores the application of the "Traveling Salesman" optimization problem for scheduling using genetic algorithms and contrasts the new approach with a classic manual workflow to discuss its advantages and value creation.

Lastly, it should be noted that this work is still ongoing research and while the results are promising, the complexity of the task, still demands additional study. At this point, the authors believe that there is not "one" single objective function representation for this complex task and encourage researchers to explore what is the best fit for their specific operations.
Data Driven Risk Analysis and Production Forecast Deration for Matrix Bypass Events in the West Sak Oil Pool, Alaska North Slope
Authors: Keith Cody D , Abbas Sayeed , Autry Sydney
Published: May 2023

West Sak is a shallow viscous oil reservoir located partially within the Kuparuk River Unit on the North Slope of Alaska. The poorly consolidated reservoir is prone to sand production, leading to a significant risk for the development of void space conduits, locally known as matrix bypass events (MBEs). MBEs result in pattern breakage and lost production capacity, and this needs to be accounted for in production forecasting. In this study, a data-driven analysis is performed to identify factors that cause differential risk for MBE formation in each well. This analysis is then used to inform the creation of a tool that determines the expected production impacts of future MBEs and derates the forecast accordingly. The well patterns and MBE history in the West Sak reservoir are analyzed for differential risk based on sand geomechanics and producer/injector well completions. Specifically, the B sand was found to have the highest MBE risk due to its lower geomechanical strength, the D sand was found to have a significant yet lesser risk, and the A sand was found to have negligible risk. MBE risk is greater for patterns with horizontal production laterals without sand control and is negligible for horizontal producers with sand-exclusion screens or vertical producers. MBE risk is reduced when vertical injectors are used instead of horizontal injection laterals. This history is used to inform the development of MBE risk type curves based on the fatigue life distribution family of curves. These curves are used as input into an MBE deration forecasting tool, which produces a range of risk-informed MBE schedules. Based on each schedule, the tool "breaks" and "repairs" patterns accordingly, determining production losses based on allocation to each pattern. These individual production loss forecasts are then averaged to provide the expected outcome for forecast deration attributed to MBEs. The tool was successful in developing reasonable deration expectations on a well-by-well basis. The work done offers a probabilistic workflow to predict well downtime due to MBEs. Data-driven evidence is provided for factors that influence MBE risking, providing a means to capture expected production losses. This evidence proves to be consistent with physical models of this enigmatic phenomenon and informs future development opportunities to mitigate this risk. The approach pursued here can be applied to other known risks to production.
High Resolution Modeling of Pore Pressure Change, Fault Slip Potential and Induced Seismicity in the Fort Worth Basin
Authors: Yao Changqing , Park Jaeyoung , Chen Hongquan , Datta-Gupta Akhil , Hennings Peter , Dommisse Robin
Published: May 2023

The seismicity rate in the Fort-Worth Basin, north-central Texas, increased significantly from 2008. Previous studies attributed the seismic events to pore pressure increase caused by wastewater injection into the Ellenburger Formation. However, hydrocarbon production from the overlying Barnett Shale was not included in those previous studies. This study introduces a basin wide 10 year modeling and analysis of pore pressure change, fault slip potential and regional seismic events in the Fort-Worth Basin considering all production and injection activities.

In order to better understand the controlling mechanisms of induced seismicity and its relationship to hydrocarbon production and water disposal, a 3D heterogeneous basin model, which incorporates all available well log data, stratigraphic data from more than 1200 wells and petrophysical analysis of 47 wells is constructed. The high resolution 90 million cell model is first upscaled using a combination of layer and areal coarsening scheme to improve simulation efficiency and then calibrated using a streamline-based inversion method with the bottom-hole pressure of 122 injection wells. The history matching period includes injection volume history and production history of more than 18000 producers for over 10 years. Next, we performed 3D fluid flow simulation on the calibrated upscaled model from which basin-wide pressure distribution was generated. Finally, fault slip potential of all the interpreted faults are calculated based on pore pressure results and fault framework model to analyze the controlling mechanisms of seismic events in the Fort Worth Basin.

There are five main seismicity sequences in the Fort Worth area, which are DFW Airport Earthquake (2008), Cleburne Earthquake (2010), Azle Earthquake (2013), Irving Earthquake (2014) and Venus Earthquake (2015). Based on the pore pressure results from fluid flow simulation, all earthquake sequences, except for the Azle earthquakes, were found to be triggered by pore pressure increase. We previously proposed a different controlling mechanism for the phenomenon observed in Azle area, which is the unbalanced loading on two sides of a critically stressed fault. The results from this study are consistent with the previous findings. Fault slip potential calculations further validate the correlation between seismic events and pore pressure increase due to wastewater injection. By plotting the cumulative distribution of fault slip potential of all faults in the basin, we could identify the faults which are most likely to slip and trigger earthquakes.

The novelty of this work is basin-wide identification of mechanisms of induced seismicity considering hydrocarbon production and fluid injection using basin scale high resolution fluid flow modeling and streamline-based inversion of pressure history.
A Comparative Enhanced Oil Recovery Study Between Low-Salinity Water and Hybrid Surfactant Process for a Carbonate Reservoir
Authors: Belhaj Ahmed Fatih , Fakir Shasanowar Hussain , Singh Navpreet , Sarma Hemanta Kumar
Published: May 2023

Over the years, water-based enhanced oil recovery (EOR) techniques have continuously been of interest for their superior technical and economic feasibility. Low-salinity water (LSW) flooding is an attractive EOR method as it can significantly improve the performance of the conventional waterflooding process all while being financially feasible at a reduced cost. Regardless of its widely acclaimed efficiency, its incapacity to substantially alter the fluid–fluid properties in the reservoir remains as one of the critical limitations of LSW flooding. The hybrid application of low-salinity water with surfactant (LSS) is a novel EOR approach with great efficiency in lowering oil-water interfacial tension (IFT) and altering the rock surface wettability. In this study, an extensive comparative analysis is held between LSW and LSS on a carbonate rock to evaluate the extent of the improvement achieved via the addition of the surfactant to the low-salinity water system. The experimental analysis between LSW and LSS is compiled based on the evaluation of fluid-fluid and rock-fluid interactions. The fluid-fluid interactions were assessed using IFT tests. The IFT between LSW and LSS solutions and crude oil was measured using the spinning drop tensiometer. The rock-fluid interactions were examined using zeta potential experiments, reservoir-condition HPHT coreflooding experiments in composite cores, and contact angle measurements in an exclusive and specifically-designed HPHT imbibition cell. The results of the IFT tests showed more effective oil-water interactions of the LSW when the surfactant was added to 1%diluted-seawater (1%dSW). IFT measurements of LSS solutions displayed significantly lower values which were substantially lower than LSW solution. The zeta potential experiments using the streaming potential method showed a clear trend of yielding more negative values for LSS solutions versus LSW at 1%dSW. The contact angle measurements confirmed a 17° difference for LSS when compared to LSW. These outcomes demonstrated that the wettability of the carbonate rock was altered from oil-wet to intermediate-wet with the addition of a low concentration of the surfactant. Coreflooding data proved conclusively that the addition of 0.2wt% of the surfactant to the LSW flooding yielded an additional 9.11% of oil recovery. The comprehensive experimental work followed in this study including contact angle and coreflooding data under HPHT conditions and zeta potentiometric studies on surface charges using whole brine-saturated cores make the findings more representative of field conditions. This paper is aimed to improve the understanding of the ability of a surfactant to improve the fluid-fluid interactions and alter the rock-fluid properties when added to LSW flooding.
Dynamic Physics-Guided Deep Learning for Production Forecasting in Unconventional Reservoirs
Authors: Mohd Razak Syamil , Cornelio Jodel , Cho Young , Liu Hui-Hai , Vaidya Ravimadhav , Jafarpour Behnam
Published: May 2023

Neural network predictive models are popular for production forecasting in unconventional reservoirs. They have the ability to learn complex input-output mapping between well properties and observed production responses from the large amount of data collected in the field. Additionally, the flow behavior in hydraulically fractured unconventional reservoirs is not well understood making such statistical models practical. Variants of neural networks have been proposed for production prediction in unconventional reservoirs, offering predictive capability of varying levels of granularity, accuracy and robustness against noisy and incomplete data. Neural network predictive models that incorporate physical understanding are especially useful for subsurface systems as they provide physically sound predictions.

In this work, we propose a new Dynamic Physics-Guided Deep Learning (DPGDL) model that incorporates physical functions into neural networks and uses residual learning to compensate for the imperfect description of the physics. The new formulation allows for dynamic residual correction, avoids unintended bias due to less-than-ideal input data, and provides robust long-term predictions. The DPGDL model improves upon a static formulation by utilizing a masked loss function to enable learning from wells with varying production lengths and by improving the results when partially-observed timesteps are present. We also develop a new sequence-to-sequence residual model to correct additional biases in the long-term predictions from the physics-constrained neural networks. Several synthetic datasets with increasing complexity as well as a field dataset from Bakken are used to demonstrate the performance of the new DPGDL model.
Prediction of Single Proppant Terminal Settling Velocity in High Viscosity Friction Reducers by Using Artificial Neural Networks and XGBoost
Authors: Ge Xiaojing , Lu Rong , Biheri Ghith , Imqam Abdulmohsin , Bai Baojun
Published: May 2023

High viscosity friction reducers (HVFRs) have been recently gaining more attention and increasing in use, not only as friction-reducing agents but also as proppant carriers. The settling velocity of the proppant is one of the key outputs to describe their proppant transport capability. However, it is influenced by many factors such as fluid properties, proppant properties, and fracture properties. Many empirical/physics-based models and correlations to predict particle settling velocity have been developed. However, they are usually based on certain assumptions and have applicable limits. In contrast, machine learning models can be considered as a black box. The objective of this study is to use machine learning models to find the relationship between the multiple factors mentioned above and particle settling velocity in order to correctly predict it. Two of the most popular and powerful machine learning algorithms, Artificial neural networks (ANN) and XGBoost, were comparatively investigated with standard data processing and training procedures. Mean Absolute Errors (MAEs) for ANNs and XGBoost were 0.010379 and 0.004253 respectively. The XGBoost learning algorithm had overall better prediction performance than the ANN model in terms of the data sets used for this study and had the potential to properly handle missing values by itself.
What Did We Learn from SAGD Applications in Three Decades, and What is Next?
Authors: Pratama Randy Agra , Babadagli Tayfun
Published: May 2023

Steam-assisted gravity drainage (SAGD) has proved to be a technically and commercially successful methodology for recovering heavy-oil in Canada. At present, there are 22 commercial SAGD projects with over 300 pads and 2,700 well pairs, contributing to nearly 1.4 million bbl/day of production. The steam growth in the steam chamber could recover up to 60% of the oil-in-place by a typical SAGD project. However, some SAGD projects are only able to present less than 20% of the recovery factor, even though they have been producing for almost decades. Currently, the steam-to-oil ratio (SOR) for most SAGD projects ranges between 2 and 4 bbl steam/bbl oil. Nevertheless, some projects are still experiencing SOR of over 4 bbl/bbl due to the aggressive steam injection.

Despite the efficacious evidence and enormous contribution to oil production, many questions regarding the current SAGD project performance are still rising. The process and execution are very complex and entail great operational excellence. The thermodynamic processes (heat transfer, wettability alteration), reservoir geology (thickness, vertical conformance, steam channelling), well designs (optimal placement of the pairs, well completions), and environmental concerns (GHG emission) are also limiting factors to be detrimental to SAGD performance. Some other techniques to recuperate heavy-oil and bitumen (e.g., co-injection)—in addition to the principal SAGD—have been insinuated and employed in the projects. The efforts only presented a 5–10% of success rate.

This paper focuses on extensive evaluation and analysis of the ongoing SAGD projects over the last three decades in Canada and what would be the forthcoming potential of mature SAGD. Lessons learned and limitations from historical and current SAGD applications based on the evaluation of 22 commercial SAGD projects are presented. Success and failure stories were evaluated from geological, technical, environmental, and operational points of view. The reasons behind the successful applications of existing SAGD practices were listed. In the end, suggestions were made as to the proper design of new SAGD projects and future practices in the matured fields.

Some new insights for the future of mature SAGD, including "zero emission" applications using solvents and reduced emission using steam additives, are also discussed. The conclusive analyses done and the recommendations made will lead to more efficient SAGD applications (new and matured) in Canada, also providing a useful road map for the other parts of the world.
Nanoparticles for the Transport of Fluids in Porous Media
Authors: Yurukcu Mesut , Ozum Baki , Ziyanak Sebahattin , Saldana Jorge Leonardo , Yegin Cengiz , Yondemli Hande , Oskay Mehmet Melih , Temizel Cenk
Published: May 2023

Fluid transport can be improved by nanoparticles when they help stimulate a reservoir's rheological properties, which involve flow, viscosity, and permeability, among other parameters. First, this work reviews the literature regarding nanotechnology in the oil and gas sector. Then, it examines a few potential nanoparticle applications that have shown varying degrees of potential to improve colloid transport mechanisms in porous media. This list includes, but is not limited to, magnesium oxide, zinc oxide, silver, silicon dioxide, pyroelectric nanoparticles, and carbon nanotubes, all of which help stimulate a reservoir, which in turn leads to better fluid transport and an enhanced rate of recovery.

The authors find that, compared to a baseline scenario that applies no nanotechnology, silicon dioxide, also known as silica, offers interesting advantages when used in laboratory settings. For example, in the case of low permeability limestones, silica helped transport fluids through the fractured rock at a better rate than without nanoparticles. Similarly, aluminum oxide shows the potential to improve rheological and filtration features inside a reservoir, stabilizing the flow of material from a well. Despite the high promise, however, it is still an early stage for field applications, where only a few trials for the use of nanoparticles have been experimented with, especially in porous media.

Nanotechnology has become a favorite topic of research across many disciplines. This work is one of the first to offer a comprehensive look at the literature on nanoparticles in the oil and gas industry while also reviewing the applications of different ultrafine elements and their potential for future research endeavors in reservoir optimization and fluid transport in porous media.
Modeling Two-Phase Flow Behaviour in a Shale Gas Reservoir with Complex Fracture Networks and Flow Dynamics
Authors: Zhang Yunhao , Yang Daoyong
Published: May 2023

In this work, a robust and pragmatic method has been developed, validated, and applied to describe two-phase flow behaviour of a multifractured horizontal well (MFHW) in a shale gas formation. As for a fracture subsystem, its permeability modulus, non-Darcy flow coefficient, and slippage factor have been defined and embedded into the governing equation, while an iterative method is applied to update the gas/water saturation in each fracture segment within discrete fracture networks. For a matrix subsystem, a skin factor on a fracture face is defined and introduced to represent the change in relative permeability in the matrix domain at each timestep, while the adsorption/desorption term is incorporated into the diffusivity equation to accurately calculate the shale gas production by taking the adsorbed gas in nanoscale porous media into account. Then, the theoretical model can be applied to accurately capture the two-phase flow behaviour in different subdomains. The accuracy of this newly developed model has been confirmed by the numerical simulation and then it is extended to field applications with excellent performance. The stress-sensitivity, non-Darcy flow, and slippage effect in a hydraulic fracture (HF) are found to be obvious during the production, while the initial gas saturation in a matrix and HFs imposes an evident influence on the production profile. As for an HF with a high gas saturation, the dewatering stage is missing and water from the matrix can be neglected during a short production time. For the matrix subsystem, a high-water saturation in the matrix near an HF can affect gas production during the entire stage as long as gas relative permeability in the HF remains low. In addition, the adsorption/desorption in the matrix subsystem can increase gas production but decrease water production. Compared to the observed gas/water production rates for field applications, the solutions obtained from the method in this work are found to be well matched, confirming its reliability and robustness.
Insights on Gas and Water Coning/Channeling Processes in a Fractured Carbonate Reservoir from Embedded Discrete Fracture Modeling
Authors: Vo Hai , Flodin Eric , Hui Robin , Earnest Evan , Trindade Marcia
Published: May 2023

Coning is the mechanism describing movement of water from an aquifer and/or gas from gas-cap into the perforations of a producing well. The interface between the fluid phases deforms into a cone shape if the reservoirs are relatively homogeneous. In fractured reservoirs, water/gas incursions can take the form of discrete channels through fractures that connect the water/gas zone to the wellbore. Coning/channeling tends to increase the cost of production operations and influences the overall recovery efficiency of oil reservoirs. The coning/channeling processes constitute one of the most complex problems pertaining to oil production. This study investigates coning/channeling in an Atlantic margin pre-salt fractured carbonate reservoir using Embedded Discrete Fracture Modeling (EDFM) to gain a better understanding of the processes in fractured reservoirs.

This study focused on a sector Discrete Fracture Network (DFN) that was used to create a full-field Dual Porosity-Dual Permeability (DPDK) model. The DFN was used to generate end member models that capture the range of connectivity, geometry, and heterogeneity of fracture systems thought to exist in the field based on well log and core analysis. The sector area of interest also included existing producers and injectors and future infill wells. The coning/channeling phenomena were modeled using the EDFM method. The models were flow simulated using representative initialization, field management logic, and well producing rules, based on the history-matched full-field DPDK model. Mitigation methods to reduce coning impacts were also investigated.

EDFM, which represents the fracture network explicitly, provides insight on gas and water coning/channeling processes in a fractured carbonate reservoir. We find that fractures can lead to local channeling and coning. The degree of channeling and coning is a function of flow rates, fracture properties, and matrix-fracture exchange which in turn depends on rock property contrast between matrix and fractures. If matrix permeability is sufficiently high, matrix-fracture exchange is significant and fractures can act like leaky pipes. The effect of local gas coning/channeling is stronger in cases of isolated fractures surrounded by lower permeability rock. Water and gas coning can occur at the same time and interact with each other. Mitigation methods such as reducing well rates and use of selective completions can be applied to manage the gas and water coning/channeling.
Application of a Novel Green and Biocompatible Clay Swelling Inhibitor in Fracturing Fluid Design
Authors: Murtaza Mobeen , Tariq Zeeshan , Kamal Muhammad Shahzad , Rana Azeem , Patil Shirish , Mahmoud Mohamed , Al-Shehri Dhafer
Published: May 2023

Clay swelling and dispersion in tight sandstones can have an influence on the formation's mechanical properties and productivity. Hydraulic fracturing is a typical stimulation technique used to increase the production of sandstone formations that are too compact. The interaction of clay in sandstone with a water-based fracturing fluid causes the clays to disperse and swell, which weakens the rock and reduces its productivity. Several swelling inhibitors, including inorganic salts, silicates, and polymers, are regularly added to fracturing fluids. Concerns linked with these additions include a decrease in production owing to formation damage and environmental concerns associated with their disposal. In this study, we introduced naturally existing material as a novel green swelling inhibitor. The performance of the novel green inhibitor was examined by its impact on the mechanical properties of the rock. Acoustic strength and scratch tests were conducted to evaluate rock mechanical parameters such as unconfined compressive strength. Further inhibition potential was evaluated by conducting linear swell and capillary suction timer tests. The contact angle was measured on a sandstone surface for wettability change.

The results showed the novel green additive provided strong inhibition to clays. The reduction in linear swelling and rise in capillary suction time showed the inhibition potential and water control potential of the biomaterial. Furthermore, mechanical properties were lower than DI-treated rock sample tested under dry conditions. With all these benefits, using green novel additive makes rock more stable and reduces damage to the formation. The green additive is economical and an environment-friendly solution to clay swelling. It is an effective recipe for reducing the formation damage caused by clay swelling.
Numerical Investigation of Energy Production from an Enhanced Geothermal System Associated with CO2 Geological Sequestration
Authors: Xue Zhenqian , Ma Haoming , Chen Zhangxin
Published: May 2023

The development of a geothermal system can supply low-carbon electricity to support the raising energy demand under the energy transition from fossil fuel to renewables. CO2 can substitute for water for energy recovery from geothermal reservoirs owing to its better mobility and higher heat capacity. Additionally, trapping injected CO2 underground can achieve environmental benefits by targeting Greenhouse gas (GHG) mitigation. In this study, different flow schemes are established to assess heat mining and geological CO2 sequestration (CCS) by injecting CO2 for the purpose of an enhanced geothermal system. The Qiabuqia geothermal field in China is selected as a study case to formulate the geothermal reservoir simulation. The results show that a pure CO2 injection into a water-saturated reservoir can provide the best performance in heat mining. Besides, this operational strategy can also provide extra benefits by producing 6.7% CO2 retention. The generated geothermal electricity under a pure CO2 injection into a CO2-saturated formation is the lowest, while its 42.1% of CO2 retention shows a promising CCS performance and the large volume of stored CO2 can supply some profits by carbon credit. Considering the assessment on heat mining and CCS, the pure CO2 injection into a water-saturated reservoir is recommended for the operation of an EGS. Under this flow strategy, well spacing, production pressure difference and fluid injection temperature are dominated in geothermal energy production. Three factors, including well spacing, production pressure difference and fracture conductivity, influence the CO2 storage capacity. In operating an EGS, a larger well spacing, a lower injection temperature and a lower fracture conductivity are suggested. While the optimal production pressure difference should be further determined to balance its effect on geothermal production and CO2 storage since it presents an opposite effect on these two parts. This work demonstrates the feasibility of heat mining associated with CO2 geological permanent storage in an EGS by injecting CO2. The proposed study proves that not only the sufficient and sustainable energy can be supplied but also a significant amount of CO2 emission can be eliminated simultaneously. In addition, the investigation of geothermal energy production and CO2 geological sequestration under different operational parameters can provide profound guidance for the operators.
Contribution of Wettability Alteration to Imbibition Oil Recovery in Low and High Permeability Conditions
Authors: Deng Xiao , Kamal Muhammad Shahzad , Patil Shirish , Shakil Syed Muhammad , Al Shehri Dhafer , Zhou Xianmin , Mahmoud Mohamed , Al Shalabi Emad Walid
Published: May 2023

Low permeability rock usually holds a large amount of residual oil after flooding. The two most important mechanisms for residual oil recovery are interfacial tension (IFT) reduction and wettability alteration (WA). There is confusion around the coupled effect between the two mechanisms. Permeability is found to be a critical factor on the coupled effect. In this study, the spontaneous imbibition oil recovery results from core plugs of different permeability by using two surfactants were compared. The comparison helps understand the impact of permeability on the coupled effect of IFT reduction and WA.

Filtered crude oil (density 0.87 g/mL, viscosity 12.492 cP), Indiana limestone cores of different permeabilities, two locally synthesized cationic gemini surfactants, GS3 and GS6, were used in this study. The spinning drop method and static contact angle method were used to measure the oil/water IFT and the wettability. Spontaneous imbibition experiments using Amott cells were conducted at the ambient condition to relate IFT reduction and WA performance to the oil recovery contribution.

Results showed that although the selected surfactants had comparable IFT reduction performance, GS3 is much stronger than GS6 in altering oil-wet carbonate rock to water-wet conditions. In core plugs with the same dimensions and comparable low permeabilities, the oil recovery values accorded with the WA performance. GS3 obtained faster and higher oil recovery (24%) than and GS6 (14%), indicating that enhancing WA alone contributes to oil recovery. The main difference between the selected surfactants was the spacer structure. It appeared that introducing unsaturation into the spacer group harmed the WA performance. Comparing different permeability conditions, GS6 obtained much higher oil recovery in a high permeability condition (922 mD) than in a low permeability condition (7.56 mD). Though permeability significantly impacted the whole imbibition process, it was more auspicious when IFT reduction became the main driving force.

This study studied the WA mechanism alone by adopting surfactants with comparable oil/water IFT values. It also features the impact of permeability by comparing the recovery curve by the same surfactant under different permeability, showing that IFT reduction contributes more to oil recovery in high permeability rock.
Monitoring of Polymer Injectivity and Mobility Control Performance in Carbonates Using Coreflood Integrated with Computed Tomography (CT)
Authors: Ahmed Shehzad , Alameri Waleed , Al-Shalabi Emad W.
Published: May 2023

Oil production enhancement from mature fields through polymer injection has gained elevated interest due to the improved mobility and conformance controls. The suitability of polymer with harsh reservoir condition and its insitu performance dictate the success of polymer-augmented waterflooding. This motivates thorough evaluation of polymer to build optimum injection strategy for the targeted reservoir. This study aims to evaluate the impact of polymer and chase water injections in high salinity carbonate rock using single-phase coreflood experiments coupled with real-time saturation monitoring. A sulfonated polymer, acrylamido tertiary-butyl sulfonate (ATBS), was utilized and polymer solutions at different concentrations were prepared in 20 wt% brine. Coreflooding integrated with computed tomography (CT) scanning was used to generate 3D images during polymer flooding in carbonate outcrop (95.2 mD) at 70°C. Polymer injection was also evaluated in a tapered injection scheme in which polymer slug concentration was stepwise reduced. Polymer injectivity, retention, flow patterns, and inaccessible pore volume (IPV) were analyzed using pressure drop, average saturation, and CT images in real time.

The results showed that the selected polymer has favorable injectivity behavior with acceptable injectivity losses (0.5-0.85) at all tested concentrations and injection rates. Polymer injection at higher concentration provided higher resistance factor, lower injectivity, and higher injectivity reduction. In-situ saturation monitoring showed polymer breakthrough before 0.8 PV with an IPV of 20%. The brine post-flush exhibited 74.1% decrease in polymer saturation after 1 PV and 99% of the polymer was recovered after 10 PVs of brine injection. For polymer augmented waterflooding with a concentration tapering mode, the IPV was reduced to 26.8%. Moreover, the chase water after tapered polymer injection showed 4.5 times high flow resistance compared to that of pre-flush brine. The chase water injection for about 1 PV reduced the retained polymer to 20% due to the increased flow resistance. This study assessed polymer injectivity and retention behavior for mobility control performance in carbonate under moderate temperature and salinity conditions. The findings of this work would guide future studies on the optimization of polymer-augmented waterflooding by using different injection schemes to improve the efficiency of mobility control process in carbonates, which would further aid in designing successful field projects.
Preparation of High Temperature Resistant High Strength Supramolecular Gels Based on Hydrophobic Association and Hydrogen Bonding and its Application in Formation Pluggingg
Authors: Yang Jingbin , Bai Yingrui , Sun Jinsheng , Lv Kaihe , Wang Jintang , Dai Liyao , Zhang Qitao , Zhu Yuecheng
Published: May 2023

The traditional chemical cross-linking method is based on the formation of covalent bonds between molecules to connect three-dimensional networks to enhance the strength of hydrogels. Although this method can significantly improve the mechanical properties, it also has many problems, such as irreversibility and fatigue. Therefore, the design and preparation of supramolecular hydrogels with high mechanical properties and good temperature resistance have very important research significance and practical value. This paper prepared a supramolecular gel with both temperature resistance and mechanical properties through hydrophobic association and hydrogen bonding, and evaluated its thermal stability, rheology, temperature resistance and pressure plugging ability. The results showed that the supramolecular gel had excellent thermal stability, and there was strong physical entanglement between its three-dimensional network structures, which made it difficult to be destroyed by increasing temperature. The excellent rheological properties of supramolecular gels enable them to maintain good viscoelastic changes in the linear viscoelastic region within the strain range of 0.1-30%. When the strain was greater than 30%, the supramolecular gel began to undergo different degrees of sol-gel phase transition, which showed that the energy storage modulus of supramolecular gel decreased. In addition, the energy storage modulus of supramolecular gel was always greater than the loss modulus in the whole frequency scanning range, and there was no intersection between the two gel and the gel always showed high elasticity. Meanwhile, the supramolecular gel still had good structure and strength after high temperature aging. Its tensile and compressive properties did not change significantly, but the color of the gel surface changed slightly, which could maintain good structural stability under high temperature environment. Supramolecular gel particles could be used as plugging materials for drilling fluid, and had excellent plugging ability of formation fractures and pores. The plugging ability of 1mm aperture plate model was up to 6.3MPa, and the plugging ability of 1mm seam width was up to 4.9MPa. Therefore, the development and application of supramolecular gel plays an important supporting role in drilling fluid plugging.
A Coupled Geochemical-Based Modeling Approach for Low Salinity Polymer (LSP) Injection: Effects of Salinity, Rock-Type, and Temperature on Polymer Rheology
Authors: Hassan Anas Mohammed , Al-Shalabi Emad W. , AlAmeri Waleed , Kamal Muhammad S. , Patil Shirish , Shakil Hussain Syed M.
Published: May 2023

The hybrid low-salinity polymer (LSP) injection technique has potential for significant synergistic advantages as an enhanced oil recovery (EOR) approach. Previous studies indicated that LSP-injection appreciably improves polymer rheology, injectivity, viscoelasticity, and displacement efficiency. However, effectively modeling of LSP injection is still lacking and necessitates realistic simulation of polymer-brine-rock (PBR) interactions in a mechanistic predictive model. In this study, the MATLAB Reservoir Simulation Toolbox (MRST) coupled with IPhreeqc geochemical software is used to gather deeper understandings of the PBR interactions during LSP-injection. This contribution relates to the sensitivity analysis performed to investigate the effects of salinity, rock-type, and temperature on polymer viscosity during LSP process. Additionally, the de-risking step involving the charge ratio (CR) analysis is considered to estimate the potential polymer viscosity loss for various salinities, rock-compositions, and temperatures. The inaccessible pore volume (IPV), Todd-Longstaff mixing model parameters, polymer adsorption, permeability reduction as well as salinity and shear rate effects on polymer viscosity were modeled via the coupled MRST-IPhreeqc simulator.

The results showed that 6-times spiked salinity (3,738 ppm) scenario is more preferable than 6-times diluted salinity (103 ppm) scenario with corresponding viscosity losses of 53% and 56%. Also, the anhydrite mineral showed the highest viscosity loss of 60% among other rock-forming minerals, followed by dolomite of 56%, and lastly, calcite with the lowest viscosity loss of 50%. For the temperature effect, the highest viscosity loss of 59% was observed at 25°C, whereas the 90°C-temperature model is the most advantageous with lowest viscosity losses of 48%. For LSP injection de-risking measures, the divalent-cation’s effect was correlated with the CR value. Consequently, it is crucial to get an optimal CR value at which viscosity loss is minimum. Based on the CR analysis, a CR > 1 suggests negligible viscosity loss in the LSP-solution, which in this study correlates to the cation threshold concentration of 130 ppm. A CR < 0.35 is expected to result in substantial viscosity loss for the LSP solution. When 0.35 < CR < 1, additional risk-analysis of polymer viscosity loss in the LSP solution is required. This contribution could also help bolster further studies and eventually aid more efficient LSP-injection designs.
Management and Outcomes of Firearm-Related Vascular Injuries
Authors: Nyberger Karolina , Caragounis Eva-Corina , Djerf Pauline , WAHLGREN CARL
Published: May 2023

Background: Violence due to firearms is a major global public health issue and vascular injuries from firearms are particularly lethal. The aim of this study was to analyse population-based epidemiology of firearm-related vascular injuries.
Methods:This was a retrospective nationwide epidemiological study including all patients with firearm injuries from the national Swedish Trauma Registry (SweTrau) from January 1, 2011 to December 31, 2019. There were 71879 trauma patients registered during the study period, of which 1010 patients were identified with firearm injuries (1.4%), and 162 (16.0%) patients with at least one firearm-related vascular injury.
Results: There were 162 patients admitted with 238 firearm-related vascular injuries, 96.9% men (n=157), median age 26.0 years [IQR 22-33]. There was an increase in vascular firearm injuries over time (P<0.005). The most common anatomical vascular injury location was lower extremity (41.7%) followed by abdomen (18.9%) and chest (18.9%). The dominating vascular injuries were common femoral artery (17.6%, 42/238), superficial femoral artery (7.1%, 17/238), and iliac artery (7.1%, 17/238). Systolic blood pressure (SBP) <90 mmHg or no palpable radial pulse in the emergency department was seen in 37.7% (58/154) of patients. The most common vascular injuries in this cohort with hemodynamic instability were thoracic aorta 16.5% (16/97), femoral artery 10.3% (10/97), inferior vena cava 7.2% (7/97), lung vessels 6.2% (6/97) and iliac vessels 5.2% (5/97). There were 156 registered vascular surgery procedures including vascular suturing (22%, 34/156) and bypass/interposition graft (21%, 32/156). Endovascular stent was placed in five patients (3.2%). The 30-day and 90-day mortality was 29.9% (50/162) and 33.3% (54/162), respectively. Most deaths (79.6%; 43/54) were within 24-hours of injury. In the multivariate regression analysis, vascular injury to chest (P<0.001) or abdomen (P=0.002) and injury specifically to thoracic aorta (P<0.001) or femoral artery (P=0.022) were associated with 24-hour mortality.
Conclusions: Firearm-related vascular injuries caused significant morbidity and mortality. The lower extremity was the most common injury location but vascular injuries to chest and abdomen were most lethal. Improved early hemorrhage control strategies are critical for better outcome.