bluuebunny/crossref_metadata_2025_split huggingface dataset:
Intermittent Pumping Optimization for Ultra-Low Permeability Reservoirs Sampling
Authors: Wang Shiyue , Fan Zhaoya , Rao Guang , Xiang Wei , Qin Rui , Sun Jun , Ren Bonan , Liu Zhiwen , Galiev Aydar , Ismail Amr 
Published: February 2024

Abstract
At present, the low-permeability reservoir fluid identification and formation dynamic evaluation mainly relies on the wireline formation test (WFT) technology in China Offshore exploration (Yang 2014 and Zhang 2018). However, because of low permeability, formation fluids cannot be continuously supplied while sampling, which makes it impossible to achieve continuous pumping during sampling operations. Therefore, there are problems such as low success rate and poor timeliness in the sampling operation of low to ultra-low permeability reservoirs. In some extreme cases, formation fluids samples cannot be obtained, which increases operating costs and exploration risks.
As a spare and passive sampling method, intermittent pumping is often used for fluid identification and sampling in ultra-low permeability reservoirs. However, at present, there is no systematic analysis and demonstration of the application limit and related feasibility of intermittent pumping in the industry, nor the scientific optimization of intermittent pumping. The rationality of the intermittent pumping scheme affects the efficiency and sampling success rate. This paper aims to find out the influencing factors of intermittent pumping, and to form the optimal intermittent scheme to guide the operation. This paper uses the Modular Formation Dynamic Tester Tool (MDT) formation testing tool as the research object. First, the lower limit of MDT was analyzed. Second, through numerical simulation, the pressure recovery ratios (flowing pressure at the end of pump stop/formation pressure) of 40%, 50%, 60%, 70%, 80%, 90% were respectively defined; 8 in-, 15 in-, 20 in- invasion depths were simulated, which represent shallow, middle, and deep-mud filtrate invasion scenarios, respectively. Three samples of purity at 20%, 50%, and 80% were set as achievement goals; a total of 54 kinds of "intermittent" pumping operations were simulate, and the total operation time in the corresponding situations were obtained as well.
During intermittent pumping, the continuous invasion of mud filtrate is the key factor affecting the pumping time and samples assurance. In this study, the mud filtrate invasion rate of different formations and mud systems was confirmed through laboratory and previous WFT data analysis. Moreover, this paper realized the world's first numerical simulation about intermittent pumping while there was mud filtrate continuous invasion. The intermittent pumping performance under different original invasion depths and different continuous invasion rates were also simulated and analyzed to provide guidance for the optimization of subsequent operations.
Through the above studies, the optimized intermittent pumping method has been successfully applied to ultra-low to low permeability reservoir WFT sampling in multiple wells, which in the past could only be abandoned or it had to rely on advanced tools.
Study on the Method of Identifying Low Resistivity Pay by LWD NMR Water Spectrum Reconstruction Based on Permeability Model in the Guantao Formation, Bohai Basin
Authors: Shi Xinlei , Ming Jun , Huang Jiangbo , Zheng Yang , Xu Guangdong , Han Zhilei 
Published: February 2024

Abstract
Low resistivity pay (LRP) has become a valuable resource globally. Estimated reserve of more than 100 million cubic meters of explored hydrocarbon is stored in LRP zones in the N1g formation in Bohai Bay. It is important to identify and evaluate them in order to improve reservoir productivity. In the N1g layer, production and well testing data have shown the resistivity of the pay zone is normally lower than the adjacent water zones. As a result, identification of these LRP zones can be quite challenging, particularly in wells where the spontaneous potential and micro-resistivity logs are not available. The purpose of this paper is to document the best practice of evaluating LRP using only LWD data.
The key step in our workflow is to perform fluid substitution on measured NMR data, such that the resulting T2 distribution removes all the hydrocarbon signal and replaces it with water signal. This reconstructed T2 represents the pore size distribution of the rock. When the rocks contain hydrocarbon, the measured T2 distribution will typically exhibit a longer T2 component. Therefore, by comparing the measured T2 against the 100% water T2, we can identify these LRP intervals.
We used core data to determine the T2 cutoff and pick the T2 log mean (T2LM) of pure water signal. Main methodology is as follows:
First step, We used irreducible water saturation (Swirr) from capillary pressure data to determine the T2 cutoff. In part two, We used core and fluid samples in N1g layer to estimate the T2LM of brine in the hydrocarbon layers in a studied field. Part three, We then used the T2 cutoff from step1 to get a continuous Swirr from LWD NMR logging data and reconstruct a T2 spectrum through Gaussian distribution centered at T2LM. And finally, We study the difference between reconstructed T2LM of pure water and the logging data to identify LRP precisely.
The proposed method addressed the challenge of differentiating LRP from water zones. By using this method, the new discovered reserve in N1g layer reached 12 million tons of oil. More than 95% of the evaluation results of N1g reservoir agreed with production data. So far, operator has drilled 44 high production wells, cumulative oil production reached 0.75 million cubic meters, which facilitated the successful deployment of oil development plan.
Geothermal Exploitation via Recycling Supercritical CO2 after Thermal Recovery in Deep Heavy Oil Reservoirs
Authors: Li Yu , Peng Chao , Khan Waleed Ali , Liu Huiqing , Wang Qing , Dong Xiaohu , Loh Wai Lam 
Published: February 2024

Abstract
After thermal flooding, the natural elastic energy of deep heavy oil reservoir tends to deplete. Yet, this reservoir retains plenty of remaining heat and oil. Supercritical CO2 (SCCO2) emerges as an optimal heat-carrying fluid and enhances heavy oil extraction due to its high mobility and unique thermal properties.
In this work, a comprehensive model of geothermal exploitation for depleted deep heavy oil reservoir via SCCO2 injection was established, in which the process of heavy oil extraction, asphaltene precipitation on permeability were incorporated. Core displacements and computed tomography (CT) were employed to obtain the variational values of asphaltene precipitation caused by SCCO2 on permeability. A reservoir simulation software (STARS), using the above various parameters such as diffusion coefficient of CO2, permeability parameter and heat transfer properties, simulates the process of SCCO2 injection for geothermal exploitation and remaining heavy oil development.
SCCO2 with remarkable diffusivity and fluidity facilitates heavy oil extraction and obtain heat energy in a wider area. Consequently, the average oil recovery evidently rises from 18.5% to 30.8%. Nevertheless, the stability of heavy oil's micellar structure is compromised by SCCO2, resulting in the aggregation and adsorption of asphaltenes onto the rock surface to promote the formation of membrane oil and reduce the effective flow area. The difference in gas-phase permeability between the core without steam flooding and the core subjected to steam flooding after SCCO2 flooding averages 7.2%. In the case of high remaining oil saturation in the depleted deep heavy oil reservoir, the backflow of SCCO2 propelled by gravity and capillary force leads to the extraction of numerous light components, leaving behind asphaltene precipitation. This process reduces the consumption of SCCO2 in the lower-temperature region. Subsequently, the swift entry of SCCO2 into regions with low oil saturation, facilitating efficient utilization of steam waste heat and formation heat.
SCCO2 exhibits the potential to enhance oil recovery in low-temperature regions and improve the heat mining rate in high-temperature regions in deep heavy oil reservoirs. The mathematical and experimental simulations offer unique and reliable insights for the advancement of depleted deep heavy oil reservoirs.
An AI Based Water Cut Sensor for Oil Wells
Authors: Altammar Abdulmohsen Ali , Alhajri Nasser Mubarak , Althawaiqib Sarah Abdulaziz 
Published: February 2024

Abstract
In the oil and gas industry, converting data to actionable information by having an accurate measurement of the well real time data flow parameters is crucial. Such measurement process is fundamental for decision making by engineers; therefore, it requires state of the art gadgets to be installed in the field to send accurate real time data to the engineer desktop to monitor, analyze and make informed decisions. Water cut is one of the important parameters of well rate testing process where it requires periodic calibrations of the metering equipment to ensure high accuracy throughout the well operating life. This calibration task of the equipment is part of the maintenance program which requires to shut-down the well and lose its potential during these maintenance activities.
This paper shows how to capitalize on real-time data from MPFM and ESP to predict the water using artificial machine learning models. the estimated water cut can be used to ensure the reliability of the existing vesical meters and optimize the required maintenance frequency which will minimize the well shut-down time. Candidates producers were selected to use and test several machine learning algorithms to evaluate their performance across different conditions and states. The study revealed good match between actual and estimated water cut figures which introduces a reliable redundancy tool to ensure equipment reliability and minimize the oil locked potential associated with maintenance activities.
Evaluation of the efficacy of various machine learning algorithms on our dataset was conducted, we trained and tested four models: random forest, linear regression, MLP, and KNN models. Our results demonstrate that the random forest algorithm outperformed the other three models, achieving a remarkably high R-squared value of 0.9731, indicating that the model accounts for 97.31% of the variance in the response variable. We also computed other metrics to assess model performance, including the mean absolute error (MAE) and mean squared error (MSE), which confirmed that the random forest model had the lowest error rates. These results suggest that the random forest algorithm is the most suitable for our dataset and may be particularly effective for predicting our response variable. Additionally, a sensitivity analysis was performed for the random forest model
This study provides a new solution for the oil and gas industry by designing a soft water cut sensor based on random forest model. The implementation of this sensor in the field can lead to improved decision making and optimization of field production strategies by accurately predicting water cut in real-time.
Foam-Assisted Water Alternating Gas (FAWAG) Injection in Offshore Malaysia Fields: A Single Formulation Approach for Enhanced Oil Recovery
Authors: Razak A. A. A. , Zainal S. , Bahrim R. Z. K. , Hsia I. C. , Razali N. , Zaidin M. F. , Zulkarnain N. N. , Amir M. I. M. 
Published: February 2024

Abstract
This study explores the development of a unified foam formulation for Foam-Assisted Water Alternating Gas (FAWAG) injection in offshore Malaysia fields. The goal is to improve sweep efficiency and enhance oil recovery by utilizing foam as a mobility control agent. The research focuses on optimizing the FAWAG process for offshore Malaysia's reservoir conditions. Laboratory experiments evaluated various foam surfactants to enhance the Water Alternating Gas (WAG) process, with three promising formulations identified. These formulations underwent rigorous testing using native sandstone core samples at high temperatures to assess their applicability in fields with lower reservoir temperatures. The results indicated that the surfactants initially increased differential pressure during the WAG cycle due to their low relative permeability. However, as they displaced gas and advanced through the core, the pressure gradually decreased. Increasing the injection rate improved foam generation, ensuring adequate foam formation. Post-flush injection with synthetic brine confirmed the effectiveness of the foam surfactant formulation. This study represents a groundbreaking effort to develop a regionally applicable foam surfactant for FAWAG injection in offshore Malaysia fields.
Locally Produced Sustainable and Resilient Surfactants for Enhanced Oil Recovery
Authors: Hussain Syed Muhammad Shakil , Kamal Muhammad Shahzad , Gbadamosi Afeez , Patil Shirish , Mahboob Ahmed , Khateeb Abdulaziz , Alotaibi Mohammed , Fahmi Mohanad 
Published: February 2024

Abstract
The chemical flooding is one of the major enhanced oil recovery (EOR) methods for recovering residual oil within the pores of rock. However, the injected chemical such as surfactant must be soluble in low and high salinity brine, compatible with reservoir ions, and stable at elevated temperatures. The main objective of this study is to explore the potential of locally produced surfactants for EOR in high temperature and high salinity reservoir environments. The design and synthesis of new surfactants were done using green or no solvents. In addition, the cleavable moieties were introduced in the chemical structure of the surfactants including amide bond which is known to exhibit less toxicity and excellent biodegradability. NMR (1H and 13C) and FT-IR techniques were used to confirm the chemical structure.
The developed surfactants exhibited excellent solubility in high and low salinity water and no precipitation, phase separation, or cloudiness was observed. The structure characterization methods were matched with the projected structure of surfactants. Moreover, the visual observation revealed no degradation in the chemical structure of surfactants even after leaving the sample over some time. The locally produced sustainable and resilient surfactants displayed excellent physicochemical properties and were found to be soluble in low to high salinity brine as well as stable over a long period. These properties showed great potential for applying these surfactants in high temperature and high-salinity carbonate reservoirs.
Application of Thermochemical Fluids as a Sustainable Energy Source in Steam Engine
Authors: Khan Fahad , Mahmoud Mohamed , Patil Shirish , Raza Arshad , Alafnan Saad F. , Arif Muhammad , Murtaza Mobeen , Mokheimer Esmail M. A. , Kamal Muhammad Shahzad 
Published: February 2024

Abstract
Thermochemical fluids of an exothermic nature are a good source of pressure and temperature and have been recognized for their application for enhanced oil recovery, wellbore stimulation, and condensate banking removal. However, these chemicals can also be utilized as an energy source to add to steam engines. Conventional steam engines rely on boilers fueled by coal, wood, or oil to heat water into steam. This study explores the possibility of replacing steam with thermochemical fluids in steam engines to drive a turbine and generate electricity.
The aqueous solution of ammonium chloride and sodium nitrite was used as thermochemicals which reacts to generate salt, water, and nitrogen gas in a closed cell. This reaction is highly exothermic and generates high-pressure nitrogen gas measured by a pressure probe. The hot nitrogen gas is then fed to the Steam Engine Model Kit (limited to 14 to 45 psi air pressure) at 14.7 psi, which generates mechanical work that can be used to drive a generator and produce electricity. The total time and the Rotation Per Minute (RPM) of the engine were measured with a tachometer to calculate the power generated for the given amount of thermochemicals and measured its energy efficiency.
The key findings show that when 30 mL of both chemicals reacted in an 80 cm3 closed cell, high-temperature nitrogen gas was generated with pressure increasing with time. The peak pressure in the cell was found more than 1765 psi after the reaction. This pressure was then utilized to generate the energy through the engine and to calculate its efficiency. Compared with steam, these thermochemicals are more stable and do not experience phase change (such as boiling or condensation) which can reduce the efficiency of the steam engine. Furthermore, these thermochemical fluids generate non-corrosive nitrogen to drive the engine which results in lower maintenance requirements and longer service life for the engine. In summary, an exothermic reaction generating nitrogen (working fluid) can run a turbine to generate mechanical work and produce electricity.
Crude Steady-State Permeability Measurements on Carbonate Source Rocks and Effect of Water Block from Fracturing Fluid on Productivity
Authors: Mathur A. , Ali S. , Eichmann S. , Gupta A. , Ali M. , Vaidya R. , Mesdour R. , Albassam M. , Cordes M. , Von Gonten W. D. 
Published: February 2024

Abstract
The carbonate source rocks (CSRs) that comprise some unconventional reservoirs contain varying amounts of organic matter, minerals, and nanometer- to micrometer-sized organic and inorganic hosted pores. High-resolution petrophysical characterization allows this heterogeneity to be categorized into rock types (RTs) for studying rock-fluid interactions. This work shows how CSR steady-state permeability to crude oil varies with RT and how exposure to frac fluids (FFs) and base frac water (FW) impacts the permeability. The results show that FW and FFs lowered the permeability to oil for five RTs and the permeability reduction was highest in the organic rich RTs and lowest in the low porosity and low TOC RTs. This paper presents an effective method to screen FFs and FW for their impact on permeability to crude oil. By completing comprehensive high resolution rock characterization to guide and complement steady-state permeability measurements at reservoir conditions we are better able to understand how rock and fluid composition impact permeability reduction. Specifically, the reported advanced NMR measurements provide valuable insight in understanding permeability behavior across different rock types.
Determination of Dissolved BTEX in Glycol Dehydrators by Developing an In-House Technique
Authors: Mahmoud Mohamed A. , Al-Salman Ahmed H. 
Published: February 2024

Abstract
Tri-Ethylene Glycol (TEG) is the most widely used solvents for natural gas dehydration process in the Oil & Gas industry. However, TEG also has a capacity to absorb other species such as benzene, toluene, ethylbenzene, and xylenes (BTEX) that may be present in the processed gas at the dehydrator contactor conditions and then desorbed at regeneration conditions giving rise to atmosphere as off-gas in atmosphere regeneration system. BTEX and other volatile compounds and light components are released in the regeneration process together with water vapor as Off-gas. In an open regeneration system, the off-gas stream is vented to atmosphere where it becomes a source of emission of various constituents including BTEX. In this paper we will elaborate the study which was conducted to establish test method to quantify BTEX at one of the gas gathering facilities handling sweet associated gas. At initial stage, there was no a well-known methodology to enable determination of BTEX from the Rich and Lean TEG. Two novel test methods were developed to find the proper and accurate quantification technique to determine BTEX concentration in Rich and Lean Glycol samples using Gas Chromatography Mass spectroscopy (GC-EA) and unique sample extraction techniques, a) by using Purge and Trap technique for Mixed diluted sample with aid of methanol 1:1 ratio. B) by Direct injection after Liquid/Liquid extraction with ultra-pure n-Hexane solvent. Both techniques were applied using Gas Chromatography Mass Spectroscopy technique using DB-5MS capillary column (30 m in length, 0.32mm inner Diameter and 0.25 µm stationary phase film thickness). The obtained results of Toluene, Ethyl-Benzene and Xylene were matched by both sample injection techniques; however, Benzene recovered concentration was 25 % lower at the direct injection mode with liquid/liquid extraction, which is due to its high volatility and low boiling point. The data has been derived through comprehensive study for the BTEX concentration inlet and Outlet of the feed gas stream of the TEG Absorber and was matched with the mass balance and flow assurance analysis. The data analysis shows high values of emitted BTEX to atmosphere by 20-35% more than the accepted limits for all components, therefore a modification has been conducted to reconnect the off-gas with the production stream which will enhance the recovery of the gas and eliminate release of BTEX to atmosphere.
Water Evacuation and Separation Improvement for Onshore Facilities
Authors: Ahmad Nur Fatihah binti@Ahamad , Mat Sharf Norfaiz Izzat binti 
Published: February 2024

Abstract
This abstract aims to showcase the activities conducted for a basic engineering study on water separation and improvement for onshore facility. The facility is equipped with crossover line between two trains and a common storage known as the Hair Pin Loop (HPL) designed to handle pigging slug volume. Over the years, an increase in water forecast has led to significant flow assurance issues. Thus, this study was initiated to comprehensively evaluate the liquid handling network.
Due to limited water processing capabilities at onshore facilities, flow assurance analysis was performed to manage liquid handling. Initially, model tuning screening was performed based on the historical data for respective feeders. The tuning activity resulted in a close match in pressure drop using a pipeline roughness of 10mm. The pressure drops also closely aligned with the historical trend scatter plot. Additional tuning check was performed by comparing the pig travel time against the historical pigging data. Based on the flow assurance result, study proceeded with adequacy check calculations to capture any debottlenecking issues at current facilities.
The analysis revealed that Train A with a maximum water content of (WC=35%) would result in HPL total liquid volume of 4246 m3 for pigging based on Max Liquid Case. Meanwhile, Train B, with a water content of (WC=5%), only reaches ~2100 m3 after 90 days. Hence regular pigging can be reimposed, as the water content in the HPL would be lower than in the case of Train A. For design purposes, assuming 20% margin on Train A total liquid volume, the condensate/water processing volume should be 5095 m3. On top of that, considering available days for liquid evacuation, minimum drain rate from HPL should be at least 27 m3/hr. Hence, it is recommended to follow the suggested pigging schedules. Furthermore, several facilities modification need to be implemented to support minimum drain rate from HPL to ensure the water evacuation inside HPL can be evacuated timely and pigging schedule can be followed. The identified modification involves modifying the piping from HPL coupled with the implementation of fluid density measurement to allow for larger water draining rate to Closed Drain System. Additionally, the condensate outlet nozzle in Condensate Separator will be elevated to enable higher water holding volume.
The paper explains a more analytical approach for liquid handling issues where liquid handling is the most common operational problem in Oil & Gas Industry for aging facilities. By having this basic engineering study and implement it in near future, the service life of assets can be extended, maintaining good integrity and reduce the risk without compromising HSE requirement.