bluuebunny/crossref_metadata_2025 huggingface dataset:
PTA Modelling Approach to Accurately Assess Formation Damage Associated to Wells Completed with Inflow Control Devices
Authors: Guerrero R. J. Phillips , Akresh S. A. Bin , Alodah M. D.
Published: February 2024

Inflow control devices (ICDs) help enforce uniform flow profiles, in horizontal wells drilled across reservoir sections with variable permeability distributions. ICD completions are installed along the dedicated horizontal sections, inducing an additional completion related skin into the total skin factor due to the pressure drop across these tools. A numerical modelling approach in this paper will quantify the ICD related skin factor to confirm the existence of any formation damage for remedial actions if necessary.

Recent software technologies have overcome this hurdle of determining each component of the apparent damage skin (the formation damage skin and the completion skin related to ICDs) by incorporating key design parameters (i.e., ICD strength or nozzle size) of these devices into the numerical modelling. This paper will present examples where a numerical approach has been implemented to estimate the formation damage skin factor from pressure build-up tests conducted in wells equipped with ICDs. In addition, the new numerical ICD modelling approach has enabled the determination of the contributing ICD completion compartments or targeted sections, which results in accurate effective well length assessment.

This paper will show examples of modelling build up test data with conventional analytical solutions, in which well test analysts can only obtain the apparent damage skin, and therefore will not be able to de-couple each skin component (the true formation damage skin and the completion skin related to ICDs), compared to the advantages of a higher resolution numerical modeling approach which captures the complex well geometries incorporating the ICD design parameters (i.e., ICD strength or nozzle size) to quantify the true formation damage beyond these tools. This numerical modelling approach will ultimately lead to an accurate estimation of the formation damage skin factor beyond these completions and will also enable the estimation of the contributing ICD completion compartment or targeted section along the horizontal wellbore.

With the ICD numerical modeling capability in complex well geometries allowing the assessment of the true formation damage, well testing analysts will confidently take reliable actions regarding remedial stimulation jobs by knowing the magnitude of the formation damage skin and will also be able to assess the contributing ICD completion compartments or targeted segments along the drilled wellbore for a higher resolution of the effective well length estimation from the pressure transient analysis perspective.
Integrated Advanced Technologies for Heavy Oil Identification Application in Saudi Arabia
Authors: Alghareeb Abdulaziz Ahmad , Al-Sultan Athbi , Al-Dhafeeri Sultan , Santoso Gagok , Alghamdi Sarah
Published: February 2024

The recent horizontal well was drilled with expectations to have some residual heavy oil separated within fault block. It required precise information for both fault and structural prediction, enhanced well placement, and completion optimization. Considering the well challenge and objective, formation evaluation was highlighted as critical where the complex pore structure will play a big role in fluid mobility, viscosity, saturation, presence of tar, permeability, irreducible water saturation, and rock quality. This paper presents integrated advanced LWD technologies that help with heavy oil identification in horizontal wells.

Ultra-high-definition resistivity imaging was used to study azimuthal formation porosity distribution in order to quantify the different porosity portions (Primary / Secondary). Following that, facies determination was obtained based on porosity spectrum, amount of secondary porosity combined with relevant logging results using neural network technique. This is significant to optimize well placement in the best reservoir rock types. Other than that, the use of LWD NMR helps to determine rock typing and formation permeability profile. This qualitative interpretation is supported by advanced mud logging services and THCnorm ratio to assist interpretation of the hydrocarbon zone.

Real-time support was done to execute the well as per the objective. The well was drilled through the A and B reservoirs and confirmed the penetration of several faults and fractures. The usage of the high-resolution resistivity images confirmed the development of secondary porosity 20% higher than matric porosity. NMR provided unique fluid typing information and quantified the heavy oil viscosity variations, which could not be quantified from density/neutron or resistivity measurements. Heavy oil with a viscosity of up to 30 cP was found in the middle zone of the A Reservoir. Oil viscosity was observed to change laterally, as it varied each time the same layer was crossed. NMR also confirmed no significant presence of heavy oil in B-Reservoir. The interpretation of Advanced Mud logging confirmed hydrocarbon bearing reservoir, that has very good agreement from LWD interpretation. Effective use of the latest technologies allows for studying and improving the current formation evaluation in carbonate reservoirs.
Low Resistivity Low Contrast Saturation Evaluation Applying Anisotropic Rock Physics Model to Sonic Logs
Authors: Zharnikov T. , Vorobiev S. , Ayadiuno C. , Vorobyev V. , Akinyose O. , Ashfaq M.
Published: February 2024

Low resistivity low contrast (LRLC) pays can contain significant additional reserves for the producing wells in decline. The most common tools for the LRLC formations analysis are triaxial resistivity and Micro-Imaging logs. However, such logs may not be available, in particular in the legacy wells. The paper describes a new method to analyze laminated reservoirs and to estimate saturation using Gamma Ray, Neutron, Density and Sonic logging suite.

The method utilizes anisotropic rock physics model to analyze sand-clay lamination. The anisotropic rock physics model allows to subdivide total clay volume estimated from Gamma Ray and Neutron-Density into the laminated and the dispersed clay fractions using shear modulus. The dispersed clay behavior is described using Reuss, Upper and Lower Hashin-Shtrikman bounds. The laminated clay is accounted for through Backus averaging. When the model is calibrated, the fluid bulk modulus is extracted, and the saturation evaluation is done using Brie equation. The Brie exponent calibration method utilizing fluid bulk modulus versus total clay volume plot has been developed.

The method has been tested on a number of wells including cases, where laminated reservoir presence was confirmed by alternative methods, for example by Image logs. It allows to evaluate saturation and to identify pay zones in majority of the test cases. The method limitations are heavy hydrocarbons presence, when oil bulk modulus is close to that of formation water, or the cases of heavy mud invasion on depth greater than one wavelength. The reason for the latter limitation is that the sonic logs’ depth of investigation is close to one wavelength. Thus, if invasion depth exceeds that, a sonic tool measures only residual hydrocarbons presence. With these two notorious exceptions, the method produces excellent results. The comparison of the dispersed and laminated clay volumes estimated by different methods allows to calibrate total clay content in the cases when X-ray diffraction (XRD) data is not available.

The paper presents novel method for the saturation analysis in LRLC reservoirs, where just limited logging suite is available. The method utilizes anisotropic rock physics model and requires Gamma Ray, Neutron, Density, Compressional and Shear sonic logging suite.
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

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

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

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

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

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

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

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

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

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

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.
An Optimized Equation of State Thermodynamic Model for Hydrocarbon Volumetric Calculations Based on Wide-Range Experimental Data
Authors: Shaaban O. M. , Ali M. , Alomair O.
Published: February 2024

Compositional modeling using equations of state is the standard thermodynamic modeling approach in the oil and gas industry. Despite its robustness, this approach yields non-unique solutions due to its dependence on the selection of heptane-plus characterization models, binary interaction sets, and volume shift schemes. This study investigates this dependence and optimizes the performance of equation of state models in predicting the volumetric properties of hydrocarbon mixtures based on it. The performances of the Peng-Robinson (1978) and the Soave-Redlich-Kwong (1971) equations of state were compared in a comprehensive study. Different combinations of published heptane-plus characterization models, binary interaction sets, and volume shift schemes were also compared. The investigated heptane-plus characterization models included 4 boiling point, 10 critical pressure, 11 critical temperature, and 4 acentric factor correlations. Five binary interaction sets were applied in addition to 5 volume shift schemes. 88,000 thermodynamic models were tested against multistage separation data for 71 hydrocarbon mixtures of crude oil and gas condensate samples. The performance of the models in predicting gas-oil ratio and liquid density was evaluated, and the influence of each model component was quantified through sensitivity analysis. Results show that the choice of the equation of state model, heptane-plus characterization models, binary interaction set, and volume shift scheme can significantly vary volumetric predictions. Based on the selected thermodynamic model, the average absolute percent error ranged from 1.5% to 33.5% for liquid density and 5.7% to 36.8% for gas-oil ratio. The sensitivity analysis revealed that the selection of the volume shift scheme, the equation of state model, and the heptane-plus critical pressure model is the most influential on volumetric predictions. The best-performing models were reported, 62% of which used the Peng-Robinson (1978) equation of state. In contrast, 82% of the worst-performing models used the Soave-Redlich-Kwong (1971) equations of state. This demonstrates that the Peng-Robinson (1978) equation outperforms the Soave-Redlich-Kwong (1971) equation in predicting the volumetric properties of hydrocarbons. The comprehensive comparative study provides great insight into the influence of different model components on volumetric predictions for hydrocarbon mixtures. Moreover, the recommended thermodynamic models provide an accurate predictive tool for hydrocarbon mixture volumetric properties that does not need prior tuning to experimental data.
Research and Practice of Smart Laying Exploiting Technology in Tight Oil Development
Authors: Zuqing He , Yuxi He , Yulin Tu
Published: February 2024

To deal with low production, low liquid and low efficiency which occur after large-scale horizontal well fracturing has been carried out to develop tight oil reservoirs in Southern Ordos Basin, and to further determine oil reservoir performance and improve the development, a number of feasible solutions and production recovery measures were determined and implemented by evaluating the potential of underperforming wells. Based on the principle of remote intelligent control, a high-performance downhole intelligent switch was developed. A smart layering exploiting technology with a low cost and a simple operation procedure was developed by applying intelligent microelectronic technology to production strings based on mechatronics, by means of astring mechanics effect calculation method used for multiple-packer combination, the deformation of smart layering exploiting string and the load in the process of water packing were calculated to avoid movement and failure of packers. This technique was tested at 5 wells. It was shown that this smart layering exploiting technology could acquire production data effectively, decrease water cut and increase production rate. Therefore, it was advantageous due to its low construction cost and a convenient layer control. Further, it may be an effective technique of water production control and oil production stabilization in tight oil reservoir horizontal wells.
Insights into H2S Scavengers and Corrosion Inhibitor Interactions for Sour Crude Applications
Authors: Alotaibi F. , Rafie M. , Almubarak T. , Alomair A.
Published: February 2024

Hydrogen Sulfide (H2S) produces an acidic fluid that is corrosive to equipment, tubulars, and facilities generating what is called "sour corrosion". One viable option to handle this gas in processing facilities is to use H2S scavengers. The main objective of this study is to evaluate six different H2S scavengers aiming to reduce the effect of H2S gas in crude oil feeds without jeopardizing the corrosion inhibitor performance that used in Gas Oil Separation Plant (GOSP).

The tested scavengers were derived from different chemical families. Some of the active compounds of these scavengers included inorganic salts, polyhydric alcohols, organic acids, chelating agents, polyols, cyclic nitrogen compounds, potassium permanganate, and zinc oxide. These scavengers underwent compatibility tests with different corrosion inhibitors using HPHT aging cell at 200°F for 24 hours. Moreover, corrosion inhibition was evaluated using low carbon sour grade steel (T-95) metal coupons at 130°F for 24 hours testing time simulating GOSP conditions. The H2S scavenging assessment was conducted using standard aqueous geochemical methods by reacting iron sulfide (FeS) with hydrochloric acid (HCl) to generate H2S. The evolved H2S was allowed to pass through a reactor vessel containing the tested scavenger. Excess or unreacted H2S that was not captured by the scavenger was gravimetrically quantified using cadmium sulfate (CdSO4) to measure scavenging efficiency. Final scavenging capacity was calculated using mass balance approach for H2S through the system.

Based on the findings of this study, three chemicals emerged with acceptable scavenging capabilities and miscibility with hydrocarbon or aqueous phases. The results indicated that liquid-based scavengers had a higher scavenging capacity compared to solid scavengers. The corrosion inhibitors excellent performance for the duration of testing. The remaining scavengers did not pass the required scavenging efficiency or showed incompatibility with the carrier fluid.

This paper shares the process of evaluating H2S scavengers for sour crude feed applications. It focuses on an overlooked incompatibility between H2S scavengers and corrosion inhibitors which can cause severe consequences if not taken into consideration as both additives can potentially lose their intended functionality.
A Holistic Approach for Mitigating Scale Deposition in Highly Sour Gas Wells
Authors: Espinosa Mauricio A. , Leal Jairo , Chen Tao , Wang Qiwei
Published: February 2024

Formation of iron sulfide scale in the Khuff sour gas wells has been a persistent problem. Accumulation of scale deposits on downhole tubing and liner has resulted in significant operation problems, such as restricting wellbore surveillance, limiting downhole intervention, interfering with downhole logging, and damaging logging tools. Heavy scale deposition can also result in a significant reduction in well productivity when reaching perforated intervals.

Extensive efforts have been devoted in recent years to solve this challenge, including scale composition determination, scaling mechanism investigation, evaluation and deployment of various descaling technologies, understanding formation damage mechanism and development of field trials of preventative methods. Removing such scales has been a challenging and complex process. Coiled tubing (CT) mechanical descaling was developed and deployed in the past, by taking advantage of state-of-the-art technologies such as high RPM milling, downhole sensors, foamed cleanup tools and sophisticated surface collecting/well testing equipment. However, CT descaling operations have become limited in recent years, due to reduced downhole pressures in some wells as field matures.

This paper summarizes the holistic approach for mitigating scale deposition in highly sour gas wells, with emphasis on the results of field implementation of the newly patented scale dissolver (ISD) technology for dealing with the iron sulfide scales at high temperatures in the highly sour gas wells. Lab studies demonstrated that this chemical product have potentials to be use for both tubing/liner/completion and formation stimulation benefits as well. Field results showed significantly increased gas productivity in conjunction improved well operational factors, as well as retrieved well accessibility. A discussion on the different lab evaluation protocols is also presented and a final update on current scale clean-up strategies and future proposals are included.

The results presented in this work represent the lately advancements on iron sulfide scale management. The new scale dissolver technology is under commercialization and can be applied in all various systems such as oil and gas producers, water injectors, and surface handling facilities.
Prediction of Microbial Induced Bacteria Using Innovative Semisolid Growth Media for General Aerobic Bacteria at Specific PH
Authors: Mahmoud Mohamed A. , Al-Salman Ahmed H.
Published: February 2024

Structural steel is widely used in marine environments because it is strong, readily available, easy to fabricate, and cost-effective. But steel is also subject to corrosion. Microbiologically influenced corrosion (MIC) plays a critical role in the pipeline corrosion process, caused by electrochemical reactions created by microorganisms that form ‘biofilms’ on immersed steel structures. The close monitoring of microbial growth is an essential process to protect the structural steel from biofilm formation. A semisolid growth media for quantitative and qualitative analysis of general aerobic bacteria (GAB) was studied and counterchecked with commercially available ready-made media Paddle tester double-sided slides, to prove the suitability to use the Total Coliform agar media with a two-day incubation at 35°C, for quantitative determination of GAB colonies at a specific pH range from 5.5 to 7.5. Several trials were conducted, including water streams at upstream facilities, rich with GAB and Coliform sources, and all the obtained results from both media were matched.
A Novel Approach to Mitigating Incoming Slug Flow at Upstream Oil Facilities Through Dynamic Behavior Modeling to Improve Efficiency in Oil-Water Separation and Energy Conservation
Authors: Kamandahalli S. , White R. , Khan Ashiff
Published: February 2024

This research presents a thorough description of a novel method for mitigating the consequences of incoming slug flow using dynamic simulation software. Additionally, it paves the way for future improvements in the model's deployment for real-time level controller tuning parameter adjustment.

In the facilities that receive multiphase wet crude from numerous distant manifolds with a number of trunk lines of expansive terrain, slug flows are quite typical. Operational challenges are brought on by the slug flow. Slug flows alter high-pressure production trap (HPPT) levels and separation efficiency, which will negatively affect the quality of the produced water and the crude oil, making handling slug flows in gas-oil separation plant (GOSP) facilities particularly difficult.

The objective of this study was to employ the dynamic simulation model to investigate the behavior of incoming slug flow to the inlet 3-Phase Separators and its ramifications on downstream equipment. The findings of the dynamic simulation are to be utilized to reduce the flow variability in downstream equipment by developing an appropriate level control scheme. This measure is aimed at enhancing the separation efficiency and conserving energy by minimizing the recycling operation of injection pumps. By utilizing HYSYS dynamic simulation model results, a novel control strategy was devised, involving the modification of the split range controller into two independent controllers. The larger valve controller was tuned for a slower response, whereas the smaller valve controller was set to be more aggressive. These adjustments improved level management and reduced the flow variations to Water Oil Separation (WOSEP) and downstream equipment. The newly developed control scheme was implemented in one of the HPPT’s and was further fine-tuned to minimize the level variations. The HPPT levels were able to be controlled automatically, as compared to the past practice of manual mode of operation. Additionally, the dynamic simulation results were employed to modify HPPT level settings to accommodate higher slug volumes, with the slug volume handling capacity increasing almost three-fold. The produced water quality from the WOSEP was enhanced, and the recycling operation of produced water pumps was reduced, resulting in energy conservation. The new logic reduced the flow variability and controllers could be operated in Auto mode. This resulted in the pumps operating at their BEP and improving energy efficiency.
Improving Energy Efficiency and Reducing Carbon Footprint of Oilfields Using a Rigorous Multi-GOSP Optimization Platform
Authors: Alhuraifi M. , Ghazal A. , He Y. , White R.
Published: February 2024

This work discusses optimizing the operations of a complex gas-oil separation plant (GOSP) network. The objective is to operate this complex network such that the required oil target is produced at minimum OPEX while leveraging the transfer capability between GOSPs. A mixed integer non-linear programming (MINLP) model is developed to optimize swing line production and processing equipment operation. This allows the systematic identification of optimal operating points, which optimizes operations. Consequently, it will result in further reduction in the processing cost and greenhouse gas emissions associated with power generation and flaring.

Many GOSPs exist to process crude production from oil wells to separate the multi-phase produced fluids into oil, gas and water. These plants include equipment, which are highly energy-intensive such as high-pressure gas compressors and water injection pumps, which are used to boost separated fluids to their final destinations. In addition, transfer lines might exist between facilities allowing for shifting production or part of it from one plant to another. As a result, there is an opportunity to optimize crude oil distribution among plants to improve asset utilization and minimize power consumption. This is in addition to the benefits of reducing greenhouse gas emissions by an average of 10% based on calculations using an MINLP model and Aramco's best practices for optimizing crude oil handling operations. The paper proposes use of parameter generation techniques to improve the model's prediction using data analytics, thereby delivering a digitalized fit-for-purpose application. This results in minimizing energy consumption while maintaining the oil target without added investment (neither OPEX nor CAPEX). Consequently, it will result in further reduction in the processing cost and greenhouse gas emissions associated with power generation.

This paper proposes a novel methodology to formulate and achieve a desired optimization solution. It also describes the level of fidelity used to model physical process equipment. This varies between use of detailed first-principles models in certain equipment to a more simplified representation elsewhere. This is done systematically based on the overall impact on the solution's accuracy and robustness.