bluuebunny/crossref_metadata_2025_split huggingface dataset:
Laboratory Investigation of a Novel Hybrid Surfactant-Gas Enhanced Oil Recovery for Tight Oil Reservoirs
Authors: Vijapurapu R. , Sarmah A. , Schechter D. S. , Nasrabadi H. 
Published: April 2024

Abstract
Enhanced oil recovery in unconventional reservoirs is gaining momentum. Many operators are commercially implementing gas injection enhanced oil recovery in their shale assets, using carbon dioxide (CO2) or enriched hydrocarbon gas. The injected gas produces oil through oil swelling and vaporization. Recently, surfactant-based enhanced oil recovery (EOR) is being considered for improving recovery in unconventional reservoirs. This study is a proof of concept of applying a combined surfactant and gas injection EOR to shale reservoirs.
In this study, a combination of surfactant assisted spontaneous imbibition (SASI) and CO2 injection in a silica-rich tight oil-wet rock representing shale reservoir conditions is investigated. The core flood experiments were conducted on tight Scioto core plugs with micro-darcy permeability. The core plugs were saturated and aged in Bakken and Eagle Ford oil. The surfactants (nonionic, cationic, and anionic) were delineated based on contact angle, IFT measurements, and spontaneous imbibition experiments prior to conducting core flood experiments. The core flood experiments show an additional oil recovery by gas injection over the high initial recovery by surfactant imbibition, irrespective of the type of surfactant used. There is at least an additional 2.8% recovery by gas injection which followed the initial high recovery of at least 50% by surfactants.
Selecting the Best Design of a Waterflooding System Using a Combination of Reservoir Simulation, Economic Decision-Making, and Stochastic Simulation
Authors: Balhasan S. , Prasad P. , Lamboi J. , Khamis A. Mohamed , Magomadov I. , Hamad A. , Lyakhovskaya V. , Hassan Z. Ul 
Published: April 2024

Abstract
It was observed that numerous simplifications are still used in the oil and gas industry when making decisions, which can lead to erroneous decisions in complex design situations. The objective of the study is to enhance the decision-making process for one of the key design factors for water-flooding projects, namely pattern size, by using a simulation-economic-simulation approach. With the help of this approach, the best injection pattern size is chosen for use in the water-flooding design.
Four reservoir simulation models of various water-flooding pattern sizes were updated with the wells, and reservoir characterization was run to obtain the production profile. Second, four economic models based on the production profiles from the dynamic models have been built to assist in decision-making for the four water-flooding pattern sizes. Thirdly, the economic model has been combined with a probabilistic simulation model based on an appropriate representation of all uncertain economic and development cost data for the four models. The optimal pattern size is then chosen using quantitative and objective analysis of all the water-flooding models to make decisions based on the economic indicators.
The results from the four economic decision-making models showed that the method is suitable for use in a complex application, such as designing a water-flooding project with various pattern sizes. The Government (first party, FP) NPV and International Company (second party, SP) NPV and IRR for pattern sizes 160 acre, 260 acre, 360 acre, and 460 acres are estimated to be 4364 $MM, 109 $MM, 17%, and 3993 $MM, 400 $MM, 23.89, and 3534 $MM, 444 $MM, 26.34%, and 2910 $MM, 350 $MM, 24.89, respectively. The economic models of decision-making output are shown in Table 1. The best design of the pattern size has been selected based on the intersection point between the two curves of the NPV that gave the best profit for both parties.
This work describes a new methodology for an integrated reservoir simulation, economic decision-making, and stochastic simulation model for achieving the optimum design. The proposed methodology, simulation-economic-simulation, is efficient and compatible with real-time operations, even in complex cases where the design is restrictive. This paper will learn how simulation insights help companies optimize their designs and systems, identify new innovations, and drive sustainable operations.
Case Study: Advancing Fracture-Stimulation Design in Tight and Unconventional High-Temperature Reservoirs to Maximize Gas Recovery
Authors: Faizal Ardi W , Kurniawan Akbar , Setyawan Aries A. 
Published: April 2024

Abstract
The attainment of commercial gas rates in reservoirs exhibiting permeability below 5 mD presents a daunting task. Since 2011, X has undertaken a strategic approach to confront this challenge by implementing fracture-stimulation in seven gas wells. The primary goal has been to elevate gas rates and recoveries beyond the achievements of previous non-fracture-stimulated completions within the same field, compounded by formidable obstacles such as high temperature (reaching 325°F) and the robust strength of reservoir rock.
The initial fracture-stimulation campaigns spanning from 2011 to 2013 yielded less-than-ideal outcomes. Inadequate material selection and frac design resulted in initial gas rates averaging 10-20 MMcf/d, with alarming decline rates of 80% per year. The root causes were traced back to crushed proppant and proppant flowback to the wellbore after several months of production.
In 2015, the second fracture-stimulation campaign marked a pivotal turning point. Leveraging insights from the 2011 campaign, the approach was revamped. The frac carrier fluid transitioned to Hi-Temp Frac Fluid, offering enhanced load capacity and temperature tolerance. Proppant composition shifted from a combination of sizes 12/18 & 20/40 to High Strength Proppant (HSP) 16/30, strategically preventing proppant crushing. Perforation density was increased from 5 SPF to 6 SPF, aiming to reduce tortuosity. Simultaneously, adjustments were made to proppant flowback material, guided by promising laboratory testing outcomes.
The implementation of these changes culminated in the successful fracture-stimulation of Q-12 and Q-14. Fracture Conductivity witnessed a remarkable 221% increase, propelling initial gas rates for Q-12 and Q-14 to 60 MMcf/d and 50 MMcf/d, respectively.
This paper intricately explores the transformative enhancements in design and materials that defined the 2015 fracture-stimulation campaign. With a focus on transitioning from dealing with oil wells to confronting the distinctive challenges of gas wells, this narrative serves as a manual of success—an illuminating guide for extracting more gas from the intricacies of challenging reservoirs.
Combustion Chamber Design Inside Wellbore to Absorb Co2
Authors: Al-Aklabi Sultan 
Published: April 2024

Abstract
In-situ electricity generation concepts and design precautions for the proposed system including the main goal which are related to reducing the environmental pollution due to the combustion of fossil fuels and emitting carbon dioxide (CO2). This reduction will be attained through a proposed smart gas well design and completion. The design is based on in-situ combustion for a gas flow in a downhole combustion chamber. Oxy-fuel combustion technique is the proposed combustion technique due to the ease of CO2 separation in this process. The proper well design will be analogous to the wells used for in-situ oil combustion to handle the high released temperature and the power generation design will combine the fundamentals of geothermal energy deployment for electricity generation. Finally, the produced CO2 from the combustion process will be reinjected downhole into an underground geological structure after being compressed and transferred to the supercritical phase. This process eliminates the CO2 production to the surface and hence reduce the environmental pollution.
The Thin-Bed Reservoir Prediction Based on High-Precision Seismic Inversion
Authors: Zhang X. , Han R. , Li Q. , Luo Y , Huang Y. , Sun J. 
Published: April 2024

Abstract
We put forward a high-resolution seismic inversion workflow to improve vertical resolution, making it possible to identify reservoirs within 10m. We employed this workflow in Ordos Basin for delineating tight gas. Our research is based on improving the vertical resolution of the inversion results to a reasonable extent. The new workflow integrates the blue filtering of seismic data, well conditioning, wavelet extracting, geostatistical inversion, and 3D geobody delineation to characterize thin-bed reservoir properties. The quality control approaches for inversion results are presented to improve the accuracy of thin-bed reservoir prediction. The complete workflow is provided and each step is described in detail to permit readers to replicate. The case study is presented for thin-bed reservoir prediction where the quality of seismic data is poor. After the new workflow is carried out, a large number of thin-bed reservoirs with a thickness of less than 10 m can be identified. The distribution of thin-bed reservoirs can be clearly delineated. The predicted result is verified to be consistent with the well data and the lateral distribution of seismic events. Due to the application of this workflow in the Ordos Basin, smaller targets can be delineated, which guides the geoscientists to evaluate the favorable traps in thin-bed reservoirs, and it can also provide a basis for well correlation and oil & gas development.
On the Significance of Hydrate Formation/Dissociation during CO2 Injection in Depleted Gas Reservoirs
Authors: Indina V. , Fernandes B. R. B. , Delshad M. , Farajzadeh R. , Sepehrnoori K. 
Published: April 2024

Abstract
The study aims to quantitatively assess the risk of hydrate formation within the porous formation and its consequences to injectivity during storage of CO2 in depleted gas reservoirs considering low temperatures caused by the Joule Thomson (JT) effect and hydrate kinetics. The aim was to understand which mechanisms can mitigate or prevent the formation of hydrates. The key mechanisms we studied included water dry-out, heat exchange with surrounding rock formation, and capillary pressure. A compositional thermal reservoir simulator is used to model the fluid and heat flow of CO2 through a reservoir initially composed of brine and methane. The simulator can model the formation and dissociation of both methane and CO2 hydrates using kinetic reactions. This approach has the advantage of computing the amount of hydrate deposited and estimating its effects on the porosity and permeability alteration. Sensitivity analyses are also carried out to investigate the impact of different parameters and mechanisms on the deposition of hydrates and the injectivity of CO2. Simulation results for a simplified model were verified with results from the literature. The key results of this work are: (1) The Joule-Thomson effect strongly depends on the reservoir permeability and initial pressure and could lead to the formation of hydrates within the porous media even when the injected CO2 temperature was higher than the hydrate equilibrium temperature, (2) The heat gain from underburden and overburden rock formations could prevent hydrates formed at late time, (3) Permeability reduction increased the formation of hydrates due to an increased JT cooling, and (4) Water dry-out near the wellbore did not prevent hydrate formation. Finally, the role of capillary pressure was quite complex, where it reduced the formation of hydrates in certain cases and increased in other cases. Simulating this process with heat flow and hydrate reactions was also shown to present severe numerical issues. It was critical to select convergence criteria and linear system tolerances to avoid large material balance and numerical errors.
Nano-Silica Gel for Water Shut-Off in Fractured Reservoirs: Experimental Insights and Promising Results
Authors: Ali Ahmed , Al-Ramadan Mustafa , Aljawad Murtada , Alabdrabalnabi Mohamed , Almohsin Ayman , Sultan Abdullah , Azad Madhar 
Published: April 2024

Abstract
In the oil industry, the pervasive challenge of water production during hydrocarbon extraction presents operational and environmental complexities, impacting costs, oil recovery efficiency, and environmental sustainability. Over the last decade, many chemical systems were developed to mitigate this problem. As the nanomaterials showed its capability to add improvement in EOR and drilling applications, it becomes a demanding to incorporate such materials in water shut-off applications. This paper delves into examining the potential of nano-silica gel to prevent water flow in fractures. While prior research has explored its utility in high permeable matrix, this study extends the investigation to fractures that contribute to unproductive water production.
In this study, a fractured limestone sample featuring a groove (middle) with a depth of 0.5 to 0.7 mm was created intentionally to simulate reservoir fractures. Nano-silica gel was injected using a core flooding system to ensure precise gel placement. The core flooding experiment was implemented at 200° F and involved three stages: 1) a pre-treatment stage for evaluating initial permeability, 2) an injection stage for the gel solution, and 3) a post-treatment stage for the constant pressure endurance test. Subsequently, the sample underwent a 3-month aging process in formation water at 167° F. Endurance tests were conducted in both the first and third months to reevaluate the plugging efficiency at 200° F. The experimental findings demonstrated the gel's effectiveness in plugging water flow in both the fracture path and matrix, achieving initially a 100% plugging efficiency. The gel was durable to high differential pressure up to 1500 with minimal leak-off rate of 0.09 ml/min. There was a substantial reduction in the average permeability across the sample, decreasing from 37.19 mD to 0.0012 mD. Analysis of the pore system through CT scans before and after treatment confirmed successful gel placement in the inlet and outlet fracture sections, as well as an invasion into the matrix. The CT scans also verified the uniform distribution of the gel along the sample length. Additionally, the gel was capable of maintaining exceptional plugging efficiency of 99.98% after 3 months from the initial treatment.
Transient Flow Analysis for Well CO2 Injection: Challenges and Methodologies to Consider for Well Design & Operating Envelope
Authors: Wejwittayaklung Kittipat , Toempromraj Wararit , Jantasuwanna Prapaporn , Chanpen Chakrit , Limniyakul Vorasak , Tasi Antoneus Sarjono , Chotphornphakorn Woravit , Thongpracharn Payap , Puttisounthorn Toon 
Published: April 2024

PTTEP has been producing from field X, an offshore gas field located in the Southern part of the Gulf of Thailand. As one of the company's strategies to become a low-carbon organization with sustainable growth and to achieve Net Zero emissions within 2050, PTTEP has initiated Thailand's first Carbon Capture and Storage (CCS) project at the X field with the expectation to reduce carbon dioxide emissions by approximately 700,000 -1,000,000 tones per annum. For this CCS project, the gas containing CO2 produced from natural gas reservoirs at wellhead platforms will be captured at the processing platform using a 2-stage membrane technology to achieve a CO2 concentration of ~95%. The CO2 will then be compressed for transportation from the facility to the injection wellhead platform and will be injected into the targeted layers of the saline aquifer and depleted reservoir for permanent storage.
Engineering studies have been conducted to identify challenges and assess the optimum design and operating measures for the future development of a sustainable CCS value chain. This paper focuses on the approach taken to analyze the requirement for well design and operating envelope to address the challenges of injecting high impurity of CO2 injection stream around 5% (one of the highest of the CCS projects) into both aquifer and depleted reservoirs.
Predicting Rock Properties from Formation Fluid Measurements: Examples, Challenges, and Future Possibilities
Authors: Anifowose F. A. , Mezghani M. M. , Torlov V. , Badawood S. M. 
Published: April 2024

Abstract
Digital transformation is unleashing unprecedented potentials to maximize subsurface data utility and explore various possibilities. The petroleum industry has witnessed for a long time the prediction of reservoir rock properties from wireline data. Recent efforts have explored the same with drilling surface parameters. While basic and advanced mud gas data have been used extensively for reservoir fluid characterization, there is the question of whether their utility could be extended to reservoir rock characterization. There is currently no empirical correlation or established relationship between mud gas measurements and rock properties. This gave us the motivation to embark on this research effort. In this paper, we will review the physics behind the relationship between mud gas measurements and reservoir properties especially porosity, and how the measurements are carried out. We will also discuss a number of research questions on the need to extend the utility of mud gas data beyond the traditional reservoir fluid typing. A physics-based workflow that follows the machine learning modeling approach will be presented and discussed. Example results of two successful applications of predicting porosity and hydrocarbon volume fraction from only mud gas data and a combination of drilling surface parameters and mud gas data respectively will be discussed. The applications are based on state-of-the-art machine learning methods including random forest and support vector machines. We used correlation coefficient, mean squared error, and mean percentage error as the models’ performance evaluation metrics. All the metrics indicate that the models gave acceptable results, proved the feasibility of this proposal, and gave impetus for exploring more possibilities. The challenges faced while implementing the proposed methodology and answering the research questions will be shared. Moving forward, other possibilities of predicting various rock properties and their respective implications will be discussed. There is immense value in utilizing only mud gas data or using it to complement drilling surface parameters to predict reservoir rock properties, especially in real time. With dedicated research, incorporating the physics of the problem, and leveraging the power of machine learning, the industry could be witnessing the emergence of a new era of "real-time reservoir characterization".
Comprehensive Assessment of Inorganic Salt Inhibitors for Clay Swelling Mitigation in Drilling and Completion Operations
Authors: Murtaza Mobeen , Allowaim Mujtaba , Rana Azeem , Kamal Muhammad Shahzad , Alarifi Sulaiman , Patel Shirish , Mahmoud Mohamed 
Published: April 2024

Abstract
Clay swelling in geological formations presents a substantial challenge during drilling and completion operations, resulting in formation damage and decreased wellbore productivity. To address this issue, various clay swelling inhibitors have been incorporated into drilling and completion fluids. Inorganic salts, such as KCl, CaCl2, NaCl, and MgCl2, are frequently employed for their inhibitory properties. This study aims to consolidate and provide a comprehensive overview of the inhibitory potential of these inorganic salts by concurrently examining multiple salts at various concentrations (1%,3%, 7%, and 10% wt%).
To assess the swelling inhibition capabilities of these inorganic salts on sodium bentonite clay, we utilized a dynamic linear swell tester. The linear swelling test was extended to a duration of 120 hours to simulate conditions in extended-reach wells, ensuring a comprehensive evaluation. Additionally, we conducted capillary suction timer (CST) tests, analyzed zeta potential, and examined particle size and sedimentation patterns of salt solutions prepared at different concentrations.
Our findings indicate a clear inverse relationship between clay swelling and salt concentration, with higher concentrations leading to reduced swelling. Notably, the lowest swelling was observed in KCl brine after 100 hours, while CaCl2 salt reached a plateau across all concentrations. Zeta potential analysis revealed that salts mitigate the repulsion between clay particles, potentially promoting flocculation. Particle size analysis confirmed the enlargement of clay particles in the presence of salts. Stability tests further demonstrated sedimentation of clay particles within the first 5 hours in salt solutions, with varying settlement patterns observed over 24 hours.
This comprehensive investigation into the swelling inhibition potential of different salts provides valuable insights for both academia and industry. It aids in designing drilling fluids and completion brines with suitable salts that efficiently inhibit swelling in a shorter time and at lower concentrations with minimum formation damage.
Efficient Chemicals for High Salinity Oily Produced Water Treatment
Authors: Xu L. M. , AlGhunaimi Fahd , Huang T. P. , Aljuryyed Norah 
Published: April 2024

Abstract
Produced water (PW) is generated in a large amount worldwide and has complex compositions. Removing oil and is usually the main focus of the treatment to meet environmental regulations as well as reuse and recycling of PW. This study aims to investigate cost-effective chemicals for high salinity PW treatment with high oil removal efficiency, short treatment time and low chemical dosage. High salinity produced water (HSPW) and low salinity produced water (LSPW) with salinity of 102,290 mg/L and 65,680 mg/L, respectively, were used in this work. Three flocculants were tested with polymers with different molecular weights and charges. The efficiency of chemicals and the optimal dosage were evaluated by separation time and transmission intensity using stability analyzer which allows a step-by-step vertical scanning of the dispersions. Oil content was also measured to evaluate the chemical performance. Zeta potential and particle size were measured to investigate the mechanism of the synergism of flocculant and polymer. Transmission intensity was used to evaluate the oil-water separation in PW in this work. High transmission intensity indicates low oil content. Polymers could not efficiently remove the oil from PW. Flocculants could reduce the oil content in PW to less than 50mg/L. However, the treatment process needs 1 or 2 hours to reach equilibrium. The combination of polymer and flocculant presented synergistic effect in PW treatment for both HSPW and LSPW with shorter separation time, higher oil removal efficiency, and lower chemical dosage. The oil content was reduced to less than 20mg/L within 10 minutes. The reduction in chemical dosage significantly improves the chemical economy. Such synergism was observed in combination of different flocculants and polymers with different molecular weights and charges. The optimal concentration was determined by the transmission intensity curve with time. The increase of flocculant concentration leads to higher transmission intensity and increase of polymer concentration leads to faster separation of oil and water. The results of size distribution and zeta potential indicate that bridging is the main mechanism of polymer to improve treatment efficiency in this work. Large floc leads to fast separation of floc from aqueous phase. This work provides the insight of oily produced water treatment using flocculants and polymers. The results show that such combination could significantly improve the treatment efficiency of high salinity PW with low chemical dosage.