bluuebunny/crossref_metadata_2025 huggingface dataset:
Sustainable On-Off Polymer Injection Reduces more than 50% CO2 Emissions, Materials Demand, and Water by Energy Storage in Formation Compressibility Achieving Equal Recovery Factor as Continuous Polymer Injection
Authors: Serrano V. , Campos H. , Allende C. , Juri J. E.
Published: April 2024

Polymer injection projects need to reduce CO2 emissions, material demand for facilities, water use, and waste to compete as viable solutions in the energy transition. Steel production process is the main contributor to CO2 emission. To address this issue, we have embarked on reducing in 50% our mobile expansion concept, which replaces conventional massive injection plants with reusable ones storing energy in the subsurface.

Here we propose to design a polymer injection project that is in line with circular economic concepts. We reduce the size of the needed facilities and reuse them by storing energy in the formation during injection periods (On) in half patterns and releasing it during shut-in periods (Off) in the other half of patterns. This mechanism is based on the high rock compressibility of the fluvial system in Manantiales Behr. Coupling the high rock compressibility with an On-Offcyclical injection strategy makes the system behave analogue to a spring-mass system that can store and release energy and has resonance conditions. We tested the idea in a conceptual simulator model, then in a sector model and finally, we implemented a pilot in four patterns that already had an oil response baseline by continuous polymer injection. Now, We expanded it to 14 patterns.

We reduced more than 50% of the needs in steel consumption and the energy requirement for constructing and mounting a polymer injection unit. These savings amount to 170 to 405 tCO2 depending on the source of the steel which represents about 0.6% of the annual CO2 reduction per year in London. The incremental recovery factor is 19% incremental almost the same as continuous polymer injection. The reservoir simulations carried out show similarincremental recovery factors with this methodology than those that would be achieved with a massive injection for the same injection wells, achieving slightly lower production peaks, but with less decline and with polymer consumption 30% less than in the case of mass injection.On-Off injection strategy allowed us to feed a greater number of injectors with the same modular plant and reduce polymer consumption by not injecting massively into all the wells of the project at the same time. By Implementing this technology, we managed to reduce the environmental impact by lowering the number of modular injection plants needed and we improved the economics of the project by reducing both the CAPEX and OPEX involved.

This process has a significant impact on all polymer flooding projects that are being undertaken in fluvial Complex Two of Comodoro Rivadavia Formation. Moreover, our mobile expansion concept with modular reusable plants (SPE-200355-MS) targets the installation of ten plants per year. Therefore, the potential reduction in emissions could be ten times greater.
Microscopic Visualization Experiment of High Temperature and High Pressure CO2-C2H6/DME Displacement in Tight Reservoirs
Authors: Wang Chengwei , Su Yuliang , Wang Wendong , Li Lei , Hao Yongmao , Zhu Haiwen
Published: April 2024

The tight reservoir exhibits pronounced heterogeneity and possesses complex physical properties, thereby constraining crude oil exploitation. Water and CO2 injection for enhanced oil recovery encounter challenges related to low sweep efficiency and viscous fingering, resulting in suboptimal recovery effectiveness. In recent years, there has been growing attention towards the synergistic advantages of oil displacement through the injection of fluids such as CO2, hydrocarbon gases, and chemical additives. This paper presents the design of a microscopic visualization experimental system specifically tailored for studying high-temperature and high-pressure composite fluid displacement in actual tight oil reservoir conditions. Based on the pore throat characteristics inside the core, a visual micro-nano scale pore throat model was created to simulate the flow of composite fluid in micro-nano channels under high temperature and high pressure conditions. The research findings indicate that adding dimethyl ether and ethane to composite gases enhances their solubility and expansion in crude oil. Comparing the occurrence characteristics of residual oil after CO2 injection development reveals that injecting a composite gas (CO2- C2H6-DME) leads to a notable reduction in residual oil in the form of Clustered and oil Porous. The experimental results show that the final recovery rate of composite gas flooding can reach 92.8%, which is 46.7% higher than pure CO2. This paper presents, for the first time, the synergistic enhanced oil recovery (EOR) technology of injecting a composite gas mixture (CO2, C2H6, DME) into tight reservoirs. This study employs microscopic visualization techniques to assess the variation in residual oil characteristics and the enhancement of recovery in crude oils driven by different gases.
Inhomogeneous Fluid Transport Modeling of Gas Injection in Shale Reservoirs Considering Fluid-Solid Interaction and Pore Size Distribution
Authors: Ma Ming , Emami-Meybodi Hamid
Published: April 2024

Gas injection presents unique enhanced oil recovery (EOR) mechanisms in shale reservoirs compared to conventional reservoirs due to the complex nature of fluid transport and fluid-solid interaction in nanopores. We propose a multiphase multicomponent transport model for primary production and gas injection in shale reservoirs considering dual scale porous medium and fluid-solid interactions in nanopores. The shale matrix is separated into macropore and nanopore based on pore size distribution. The density functional theory is employed, accounting for fluid-solid interactions, to compute the inhomogeneous fluid density distribution and phase behavior within multiscale matrix. The calculated fluid thermodynamic properties and transmissibility values are then integrated into the multiphase multicomponent transport model grounded in the Maxwell-Stefan theory to simulate primary production and gas injection processes. Our research underscores the precision of density functional theory in capturing intricate fluid inhomogeneities within nanopores, which is overlooked by the cubic equation of state. The fluid system within varying pores can be classified into confined fluid and bulk fluid, separated by a pore width threshold of 30 nm. Distinct fluid compositions are observed in macropores and nanopores, with heavy components exhibiting a preference for distribution in nanopores due to stronger fluid-solid interactions compared to light components. During primary production period, the robust fluid-solid interactions in nanopores impede the mobility of heavy components, leading to their confinement. Consequently, heavy components within nanopores are difficult to extract during primary production processes. During the CO2 injection period, the injected CO2 induces a significant alteration in fluid composition within both macropores and nanopores, promoting fluid redistribution. The competitive fluid-solid interaction of CO2 results in efficient adsorption on pore walls, displacing propane from nanopores.
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

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

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

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

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

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

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

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

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

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

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.
Achieve Zero Shutdown by Optimizing Design and Tie-In of Compressors in Brown Field Projects
Authors: Kumar Sampath , Gupta Kapil Kumar , Al Wahedi Faisal
Published: April 2024

As part of Define stage study of new oil producing facilities, it was recommended by Asset owners to reduce CAPEX (Capital Expenditure) and OPEX (Operating Expenditure) by

Designing new facilities to have maximum synergy with existing oil trains. Utilize the spare capacity of existing oil and gas processing trains. Achieve ZERO / minimize shutdown of the existing facilities.

Adequacy study for existing facilities was carried out and it was concluded that spare capacity of Oil processing trains are adequate however existing LP (Low Pressure) /MP (Medium Pressure) Compressor trains (3 × 50%, 2 operating + 1 standby) had bottlenecks. Therefore, it was recommended to add the new LP / MP (2 × 100%, 1 operating + 1 standby) train parallel to the existing LP/MP Compressor trains.

Further Define stage Adequacy Report also recommends addressing existing issues during Execute stage:

Issues related to load sharing controller of existing compressors along with new load sharing required for new compressors. For major modification required in piping network, Tie-ins, and pipe routing. Address design, safety & constructability constraints.

All the above are triggers for escalation of shutdown durations, project cost and major loss of revenue for Asset owners.
Challenges to Opportunities; Water Management Journey from Oman South
Authors: Al-Hajri A. , Al-kindi S. S. , Harrasi A.
Published: April 2024

Efficient management of produced water presents an ongoing challenge in the oil and gas industry due to continuously increasing produced water volumes and the challenges related to handling, treatment & disposal as well as the associated energy consumption and emissions. Proper water management is especially important when produced water volume starts to affect the Oil production. This paper focuses on a specific cluster located in southern Oman, exploring the techniques employed to address these challenges and transform them into opportunities. The study highlights the importance of restricting the volume of water produced from the reservoir while maintaining optimal oil production levels, leading to the deployment of Autonomous Inflow Control Valves (AICVs), which are currently in use within the cluster. Furthermore, the paper delves into common methods for surface-level produced water handling and treatment, such as Deep-Water Disposal (DWD) and Water Injection (WI) wells. This paper showcases how DWD wells presented an untapped potential for a nearby field. Moreover, in line with energy consumption and emissions reduction requirements, and with a commitment to environmental sustainability, the paper showcases the company's environmental sustainability approach by utilizing Water Treatment Project (WTP) that significantly reduces energy footprint by relying on mechanical and biological processes, eliminating the need for pumps. This paper illustrates the efficacy of these subsurface control techniques and their substantial contributions to sustainable produced water management within the region, along with the surface-level handling and treatment approaches employed.
Vibroacoustic Technology for Real Time Leak Detection and Pig Tracking on Offshore and Onshore Pipelines
Authors: Marino M. , Gomes A. P. , Rota M. , Cesari S.
Published: April 2024

The primary objective of this paper is to present and assess the effectiveness of Vibroacoustic Technology as a reliable and robust asset integrity monitoring system for offshore and onshore pipelines by analysing data from actual leakages and pigging. Specifically, the focus will be on its capability to detect leaks and track Pipeline Inspection Gauges (PIGs) in real-time.

Vibroacoustic Technology is a robust detection system employed in pipeline networks to identify leakages, deforming impacts, PIGs location and various types of third-party interferences (TPI). By strategically placing specialized sensors at regular intervals along the pipeline, this technology can effectively capture vibroacoustic waves generated by these activities as they propagate through the pipeline structure and transported fluid. The data collected for leakage detection and localization is also utilized for real-time tracking of PIGs to determine their precise location.

Following the installation of vibroacoustic sensors on the pipeline, comprehensive test campaigns were conducted to simulate various spillage scenarios. These test campaigns not only assessed the performance of the detection system but also evaluated its response time. After collecting data for approximately one month, the system was calibrated and officially deployed. With the introduction of Vibroacoustic Technology, the tracking of PIGs became possible using the same data collected by the sensors, providing real-time updates on the PIG's position and traveling velocity. Significant research and testing have been carried out worldwide on the application of VT in pipelines, yielding exceptional results on both transferring and shut-in conditions. This paper presents the outcomes of a spill test campaign conducted on a pipeline in Italy, focusing on the system's sensitivity and the statistical data obtained during the passage of a PIG.

Vibroacoustic Technology is a reliable detection system designed to meet the demands of complex pipeline operations, cost-effective, non-invasive and easy retrofitting. By strategically placing sensors every tens of kilometres apart along the pipeline, it can detect even small leakages caused by corrosion or illegal tapping. Real time monitoring of pipeline integrity helps prevent severe environmental contaminations associated with leakages, making the system indispensable in ensuring the safety and efficiency of pipeline networks. Furthermore, the system provides the added benefit of accurate PIG tracking.
Implementing Business Analytics Tool to Optimize Deep Shale Gas Drilling Operations: A Visualization Approach to Analyze Drilling Performance
Authors: Chen Lu , Yan Juntao , Liu Jie , Liang Yanchao , Li Wei , Qi Peng , Baojian Hao , Guangzhi Shi , Tian Peng , Yang Bo , Liu Bingqi , Xu Ziyuan , Yang Zhigang
Published: April 2024

Our work combines a business analytics intelligence tool with advanced big data management techniques, and applied the tool to drilling performance analysis and decision-making processes for deep shale gas operations.

An advanced data processing workflow including transforming and mapping data was designed and implemented to unify current and historical drilling operations data into a unique dataset. The latest operations information is regularly collected and updated through an automated data querying process, which saves the effort of repeating data wrangling manually and eliminates the risk of human error. A business intelligence (BI) tool is used to promote the engineering of the data analytics process, create relevant key performance indicators, design data models, and establish a tracking and evaluation system. Finally, the BI visualization tool is used to generate and publish comprehensive cloud-based dashboards and reports.

The BI visualization dashboard enables oilfield companies to perform efficient and accurate analysis of drilling performance. The BI tool allows

Effective identification of rotary steerable system (RSS) utilization, drilling efficiency, failures, and downhole applicable conditions on basis of real job data, thereby enabling informed RSS management decisions Clarification of high performance of the RSS for making strategic decisions for high profile jobs Classification of rotary steerable tool failures, nonproductive time trends and monitoring maintenance strategies to reduce failures that have a major impact on drilling operations performance Incorporation of real-time operational data and detection of record-breaking jobs Development of custom drilling operations performance reports Reducing the workload for data collection and chart making with faster acquisition of more accurate data than with previous methods Customized and accurate documentation of drilling performance data in a consistent and standardized fashion Publishing of specific guidelines for RSS applications in deep shale gas drilling Performing technical analysis for operators

The integration of BI tools in drilling operations is a step change in how service companies and oilfield companies are analyzing and monitoring operation performance (efficiency and quality) to optimize drilling and minimize costs. BI analysis using existing techniques and resources was conducted for a dataset from more than 100 wells with over 1,000 runs in a Sichuan basin deep shale gas field.
Study on Production Improvement with Multi-Scale Geomechanical Modelling for Horizontal Wells in Unconventional Resources
Authors: Zhang Jie , Zhou Wei , Wang Peng , Wu Yiming , Wang Peng , Liu Zhiliang , Li Guohui , Tian Lei , Zhan Qigui , Mu Xingyu , Huang Xingning
Published: April 2024

To address the difficulty of increasing production in tight and naturally fractured reservoirs in the Tarim Basin oilfield, a study was conducted to maximize the volume of reservoir transformation through close-spaced fracturing. The parameters of close-spaced fracturing were optimized, reducing the average cluster spacing to 7m and the average stage spacing to 52m, significantly improving the degree of fracture control in the reservoir. This study developed key technologies for large-scale volume fracturing in horizontal wells, including high-rate horizontal wells with a flow rate of 16-20m3/min, freezing gel for creating main fractures, slickwater for creating complex fracture networks, small particle-size proppants in quartz sand, and high-strength proppants, which effectively supported main fractures and various level discontinuity fractures. Field trials have demonstrated that this technology significantly improves the effectiveness of fracturing in horizontal wells, with a cumulative oil production of 10,969.3m3 in 18 months, more than triple the production of previous horizontal wells. The results of this study indicate that large-scale close-spaced volume fracturing in horizontal wells can effectively address the challenge of low reservoir productivity in the Tarim Basin, providing strong technical support for the efficient development of deep oil and gas resources in the region.
Effects of Structural Parameters of Flow Tube on Flow Characteristics Near a Blowout Well
Authors: Li Yiming , Yang Qishuang , Wang Ning , Ahmad Sheraz , Liu Yiying , Lv Zhongjin
Published: April 2024

Well blowouts are likely to cause fires and wellhead damage. The flow tube is a necessary device to raise the flame to reduce the temperature around the wellhead and provide suitable conditions to reset the wellhead device. The effect of flow tube structure and posture parameters on the flow field near the wellhead have been investigated and parameter optimization of the flow tube designing has been carried out.

In this study, the well blowout jet interacting with the flow tube has been simulated using the most practical k-e turbulence model. We investigated the effects of the ratio of the inlet and outlet diameter ranges (1:1-2.4:1) and the length of the lower section ranges (1.5m-3m) on the distribution of the velocity and pressure of the two-section flow tube. The drainage effectiveness and flow control capability were analyzed. The effect of changes in height and angle on the forces affecting the flow tube during buckling-up-installation was examined. For evaluation purposes, the design parameters of the flow tube were optimized.

For verification of model accuracy, the numerical simulation results were compared with the classical solution of the free jet. In the results section, it can be observed that the diameter ratio affects the inlet pressure, velocity, and entrainment of the flow tube. A strong negative pressure profile is witnessed in the straight flow tube and for every 12.5% increase in the diameter ratio, the negative pressure values at the inlet near the wall decrease by nearly 40% while the diameter ratio is increased by 12.5 percent approximately with the volume of entrainment diminished by 8%. When the diameter ratio of 2:1 is considered, the pressure at the center of the inlet changes from negative to positive. Therefore, we believe that increasing the diameter ratio can effectively reduce the negative pressure and entrainment volume. The length of the lower section also influences the inlet velocity and pressure distribution. With the increasing length of the lower section, the inlet velocity and entrainment decrease with a convergence profile. The results of the flow field when flow tubes inclined from 5° to 15° demonstrate that strong vortices are generated in the lower section. During this the overflow velocity increases by increasing the inclination angle.

This study provides a better understanding of the mechanism of how the flow tube controls the jet flow and provides a theoretical foundation for the design of the flow tube. It concludes that the diameter ratio of the flow tube and the length of the lower section are the key parameters. It also provides a deeper insight into hazards near the wellhead, which can reduce operational risks for field operators.
Co-Injection EOR Technology Increases Recovery and Reduces GHG Emissions
Authors: Wasylchuk G.
Published: April 2024

Oil demand continues to rise and is not projected to peak until at least 2030, according to the International Energy Agency, or possibly even later as per OPEC. Despite this, many publicly listed oil companies have announced aggressive emissions reduction targets. For instance, Canadian companies Cenovus and CNRL have committed to achieving net zero by 2050. Cenovus aims for a 35% absolute reduction of GHGs by 2035, and CNRL targets a significant reduction from oil sands operations by 2030.

CEOs often cite the challenge of generating acceptable returns on emissions reduction projects as a major barrier to decarbonization, as reported by the Boston Consulting Group in 2023. Abatement technologies such as Carbon Capture, Usage, and Storage (CCUS) require substantial investment and are unlikely to yield positive returns for several years. Furthermore, they are expected to remain relatively small in scale and impact in the near to mid-term future, according to the World Economic Forum in 2023.

The traditional and conventional method of heavy oil extraction in Alberta and Saskatchewan has been marked by inefficiencies, primarily due to low recovery rates that leave upwards of 90% of the resource untapped. The process is characterized by high emissions and significant capital investment, rendering the development of smaller deposits economically unfeasible. Heavy oil production typically necessitates a substantial upfront capital investment in large, permanent central facilities, leading to a planning horizon of five to ten years for the optimization of a steam plant and production installation. Additionally, securing regulatory approvals for land disturbance and water supply requires considerable time and effort.
Intelligent Metering and Automated Gas Lift Control System with EDGE
Authors: Liu Lulu , Pinyan Liu , Fangfang Wei , Xingyu Jiao , qi Wei , Chaodong Tan
Published: April 2024

In order to optimize gas lift rates and maximize production profitability for gas lift wells, a ‘cloud-edge-end’ intelligent control system is developed. By leveraging an ensemble of artificial intelligence (AI) agent at the edge, the system is able to consume real time data and provide automatic gas lift control.

Flow meters is integrated with machine learning models to ensure measurement accuracy. Machine learning (ML) is used to build the AI agent which embedded in the wellhead edge after fine tuning. Real time data from sensors and meters are sent to the AI agent. It calculates the optimum flow rates with edge analytics capabilities and compares with the flow values detected by flow meters. When the detected value is inconsistent with the calculated one, the AI agent will take actions (rewards or penalties) automatically by regulating the gas lift injection valve and production choke, until meeting the optimization goal. The solution is able to automatically control the gas injection rate and liquid production rate in a close loop system with edge architecture. Compared with manual control, the constant flow rate is maintained and flow fluctuations are avoided.