bluuebunny/crossref_metadata_2025 huggingface dataset:
Low Salinity Water and Foam Flooding in Sandstone Reservoirs Bearing Heavy Oil
Authors: Al-Saedi Hasan N. , Al-Rubaye Wisam I. , Kassim Ali , Fakhir Rahman , Al-Bazzaz Waleed , Al-Sayegh Salih , E. Flori Ralph
Published: May 2024

This study investigates foam and water flooding (especially low salinity (LS) water flooding). Generally, injecting LS water alters sandstone wettability towards being more water-wet, is an effective EOR technique that improves oil recovery. Foams were also employed to enhance oil recovery due to its ability to increase residual oil mobility and sweep efficiency. Combining both LS water and foam into a novel attempt that takes advantage of the relative strengths of both EOR methods. This EOR combination was tested on Berea sandstone cores saturated with heavy oil. The ultimate outcome from this work is a "recipe" of EOR methods in combination, which utilizes LS water and foam to achieve recovery of over 72.65 percent of OOIP in core flooding tests. The core-flooding results showed that an increased heavy oil recovery was obtained by injecting foam and lowering water salinity. The contact angle and interfacial tension (IFT) measurements agreed with the core-flooding results.
Reliable and Efficient Algorithms to Optimize Gas Well Intermittent Production Through Automatically Intelligent Control
Authors: Wu Qingxia , Han Guoqing , Yang Dingding , Zhu Zhiyong , Peng Long , Ma He , Liang Xingyuan
Published: May 2024

Liquid loading poses a prevalent challenge in gas well production. To maximize the gas production rate and reduce the cost of deliquification, intermittent production is often applied. However, optimization of operation parameters remains challenging due to the transient behavior of the reservoir-wellbore system. In this study, efficient algorithms are proposed to automatically optimize the parameters in real-time to remove the liquid efficiently and maintain gas production, through which the recovery factor can be extended.

Firstly, we build a comprehensive model that couples the reservoir transient behavior with wellbore dynamic characteristics. The coupling model lays out the fundamentals for reservoir-production system analysis. Then, two intelligent optimization algorithms, namely the Genetic Algorithm (GA) and Proximal Policy Optimization algorithm (PPO) are developed to obtain the optimal operation parameters, which are the key elements in intermittent production management. Finally, the optimal production system is determined by jointly controlling the gas production rate and bottom hole pressure in the coupled reservoir-wellbore model to adjust choke and open-shut intervals for obtaining the maximum cumulative gas production rate and drainage rate.

It is observed that the proposed reservoir-wellbore coupling model can characterize reservoir transient performance and capture the dynamic behavior of multiphase flow in the wellbore. The model facilitates the real-time analysis of the inflow-outflow system automatically, which can output optimal parameters to manage the operation. The global optimal solution of gas production rate and bottom hole pressure can be discerned from a set of combined parameters by using the GA algorithm. PPO algorithm can optimize the system by applying variable step size search and multivariable synchronous optimization depending on the environmental state, which can be a closed-loop optimization that allows automatic control/adjustment in the system. The simulation results indicate that intermittent production designed by two algorithms has higher cumulative gas production compared with continuous production scenarios, showing the significance of proper management in intermittent production. Additionally, it is noteworthy that GA and PPO exhibit no significant difference in gas cumulative production. Each algorithm has its special adaptability: the GA is suitable for the coupling model characterized by ideal homogeneity, whereas the PPO is more appropriate for the coupling model with complex heterogeneity, interference, transient response, and randomness.

This presented work demonstrates the ability of the GA and PPO optimization algorithms to optimize the coupled reservoir-wellbore model for solving the optimal operation parameters in intermittent production, which has great significance in avoiding the liquid loading phenomenon and improving gas recovery.
Recommended Practices and Lesson Learnt from High-Efficient Hydraulic Fracturing Towards China's Unconventional Resources Recovery
Authors: Tong Zheng , Zhang Shaolin , Li Shuai , Sun Qiang , Xue Jianjun , Qian Jie , Wang Xinzhong , Weng Dingwei
Published: May 2024

The latest research progress in the field of unconventional oil and gas reservoir hydraulic fracturing technology in China from the aspects of fracturing process optimization, electrification of fracturing equipment, upgrading of key devices, development of dissolvable materials, and R&D of downhole tools were proposed in this paper. Particularly since 2020, through a large amount of technical research and field trials, a comprehensive upgrade of the hydraulic fracturing technology system has been realized, supporting the confirmation of shale oil and gas geological reserves and the construction of scale benefits in the Sichuan Basin and Ordos Basin.

The electrification upgrade of fracturing equipment was continually on the way, in 2022, the number of electric driven fracturing operations by PetroChina reached 8,474, with an electricity replacement rate of 27.4%, saving 39,000 tons of diesel and reducing carbon emissions by 32,000 tons. Two types of dissolvable magnesium alloys were developed, with high-strength dissolvable magnesium alloy having a tensile strength of over 500MPa and a high elongation dissolvable magnesium alloy having an elongation rate of over 60%. The high-strength magnesium alloy was used as the core component of the delay mechanism in the delay toe sliding sleeve, ensuring the reliability of the toe sliding sleeve during the whole wellbore pressure test and sliding sleeve opening, improving the efficiency of the first section fracturing process in horizontal wells. The high-strength magnesium alloy was also used for the main body of bridge plug, and the high elongation rate dissolvable magnesium alloy was used as the sealing part, improving the sealing pressure performance from 70MPa to 90MPa and widening the temperature tolerance range to 20-200°C. In 2022, more than 20,000 sets of dissolvable bridge plugs were used by PetroChina. The composite low-density temporary plugging ball was developed, based on high-strength magnesium alloy with a hollow design wrapped in dissolvable rubber, allowing for variability in density and shape within a certain range, and field tests of temporary plugging fracturing showed an average pressure increase of 11.2MPa.

The comprehensive progress of domestic hydraulic fracturing technology systems from process to equipment, tools and materials has promoted the low-carbon and efficient utilization of unconventional resources and provided feasible technical ideas for the next step of high-quality development.
Unravelling the Tectonic History of the Oman Mountains Using Structural Restoration in the Emirate of Sharjah, UAE
Authors: Thurley Callum , Cowgill Mark , Stewart Donald , Kay Sarah , Cox Edward
Published: May 2024

The world-class outcrops of the MusandamPeninsula and Northern Oman Mountains have given valuable insight into the geological setting, history and genesis of the fold and thrust belt in the northern United Arab Emirates. This paper provides new insight into the tectonic evolution of the Northern Oman Mountains in the Emirate of Sharjah using state-of-the-art 3D seismic and reprocessed legacy 2D seismic via structural restoration.

Seismic interpretation has revealed that two thrust systems exist in the subsurface separated by a detachment which lies in Upper Cretaceous strata. A deep thrust system forms at Arabian Platform level (Lower Cretaceous and older) and a shallower thrust system within the Aruma Group (Upper Cretaceous and younger) is present as well. Throughout much of the thrust belt in Sharjah, the Aruma Group subcrops beneath the desert and outcrops along narrow ridges that protrude from it at present day. The thrust front is characterised by a series of en echelon pop-up structures which form a north-south trend across the Emirate. It is proposed that these transpressional features formed along pre-existing north-south trending lineaments. These are the most prospective hydrocarbon traps in the Northern Emirates and include the Sajaa, Moveiyed, Kahaif, Mahani, and Margham gas-condensate fields.

The area has been through a series of tectonic events, related to extension in the Permian, tectonic quiescence throughout much of the Mesozoic, an ophiolite obduction event in the late Cretaceous, and in line with the general view, a second compressional event in the Miocene related to the Zagros Orogeny. In the Miocene, the thrust front pop-up structures acted as buttresses and prevented the westward movement of the shallow thrust belt within the Aruma Group, which led to duplexing and intense imbrication to the east of the thrust front and to the west of the encroaching Semail Ophiolite.

The interrelationships between these events, stratigraphy, and basin evolution are discussed in this paper with a view to unravelling the tectonic history of the Northern Oman Mountains.
Unloading Gas Condensate from the Wellbore Using an Innovative Foamed System
Authors: Alsultan Sharefah , Karadkar Prasad , Harbi Bader , Shehri Tamim
Published: May 2024

Gas production can be enhanced by the unloading of liquid accumulated in the wellbore. These liquids can be either formation water or gas condensate. Conventionally, liquid loading is addressed by dropping soap sticks into gas well or nitrogen lifting operation without foaming. During this process, achieving a stable foam with condensate is a challenging task. In this paper, an advanced foaming system was developed to unload both formation water and condensate in addition to nitrogen lifting.

The novel foaming system consists of aqueous and hydrocarbon soluble foaming agents. The aqueous foaming agent is an amphoteric surfactant, whereas the hydrocarbon based foaming agent is a fluoro-polymeric surfactant. The test fluid was prepared by mixing foaming agent with synthetically prepared formation water and a condensate sample separately. The foamability of surfactants was assessed by using a static foam analyzer, measuring foam half-life. Liquid unloading phenomena was investigated using an in-house developed column flow test. Foam rheometer was used to measure stability under high-pressure high-temperature (HPHT) conditions.

The stability of foam greatly depends on ideal hydrophilic-lipophillic balance (HLB). This balance can be achieved by optimizing the foaming agents which significantly rely on liquid drainage, gas diffusion, and foam rupturing at high temperature. The aqueous foaming agent was analyzed from 0.5 to 1% (vol) using synthetically prepared formation water, whereas the hydrocarbon based foaming agent was optimized to 0.5% (vol) using actual condensate samples. The column flow test, which measures liquid unloading characteristics, was conducted to ensure liquid unloading from the glass column. Nitrogen gas was purged in the column from the bottom with 200 to 400 ml/min and the rate of foam displacement was measured. The stability of the foam prepared using an aqueous foaming agent with formation water was analyzed by foam viscosity at various qualities using N2 gas at different shear rate form 100-500 1/s at 1500 psi and 300°F. The effect pressure on foam viscosity was also studied to assess foam stability under HPHT conditions.

Liquid unloading using soap sticks is limited to liquids accumulated with aqueous fluids. In this paper, the advanced foaming system addresses both aqueous and hydrocarbon liquids accumulated in the wellbore that can be applicable for high temperature wells. These foaming systems can be injected with N2 with coiled tubing operation.
Extensive Study on the Influencing Parameters of Sc CO2 Foam Viscosity for Enhanced Oil Recovery and Carbon Sequestration: A Machine Learning Approach
Authors: Bashir Ahmed , Kasha Ahmed , Patil Shirish , Aljawad Murtada Saleh , Kamal Muhammad Shahzad
Published: May 2024

Foam flooding has been used to control gas mobility during oil displacement and CO2 sequestration processes in subsurface porous media, mitigating the negative impacts of low gas viscosity, reservoir heterogeneity, and gravity override. In this research, we study the application of machine learning (ML) to develop a data-driven prediction of the effective viscosity of supercritical CO2 foam (Sc-CO2) for enhanced oil recovery (EOR) and CO2 sequestration. The ML approach is used to overcome the challenge of using physical correlations to account for the effect of key experimental parameters on the viscosity of supercritical CO2 foam. The experimental data for evaluating the effective Sc-CO2 foam viscosity were measured using a high-pressure high-temperature foam rheometer (Model 8500) under different temperatures (50-110 °C), pressures (1000-3000 psi), foam qualities (30-90%), and surfactant concentrations (0.1-0.5 wt.%) at shear rates between 100-1450 s−1. A total of 5,552 data points were used as primary data for developing supervised ML regression models. Machine learning algorithms from the Scikit-learn library, such as K-Nearest Neighbors (KNN), Random Forest (RF), Gradient Boosting (GB), and AdaBoosting (AB), were used.

The results revealed that machine learning algorithms generated models for the effective viscosity of Sc-CO2 foam with predictive accuracies of 0.989, 0.987, 0.941, and 0.723 for RF, KNN, GB, and AB, respectively. The RF and KNN algorithm demonstrated superior performance among all the other algorithms, with RF being better in terms of accurate viscosity prediction across different viscosity values. This paper provides data-driven approach that can predict the effective foam viscosity under different reservoir conditions which leads to the design of an optimum injection strategy and effectively controls Sc-CO2 mobility for EOR and CO2 sequestration.
Crucial Factors for in-Situ CO2 Monitoring in CO2-EOR Projects Using Pulsed Neutron Well Logging
Authors: Kim Y. , Akang N.
Published: May 2024

Carbon dioxide (CO2) injection for enhanced oil recovery (EOR), also known as CO2-EOR, has become increasingly important due to the growing need for CO2 utilization and sequestration. CO2 monitoring is an integral part of the CO2- EOR process. Pulsed neutron (PN) well logging is an efficient and effective technology for understanding subsurface CO2 propagation and quantifying multiphase saturation. This paper discusses the critical factors—well conditions and reservoir properties—in designing a PN well logging program and analyzing PN data.

The Monte Carlo N-Particle (MCNP) simulation is a stochastic forward modeling method that generates PN tool responses under diverse well and formation conditions. With a series of MCNP models, including perturbations of various well logging environments, the characteristics of key PN measurements were delineated. This enabled the establishment of best practices in PN well logging operations and data analysis for in-situ CO2 profiling. The requirement for the PN tool is to be slim in terms of the outer diameter (i.e., 1.69 inches), allowing through-tubing deployment, and to have three scintillation gamma-ray detectors, enhancing the formation sensitivity compared to traditional dual detector-based PN tools.

We constructed MCNP models of time-spectra-based well logs; inelastic and thermal neutron capture logs were simulated considering several vital parameters—wellbore fluid, formation lithology, annular space materials, in-situ oil and CO2 densities, and reactions between CO2 and formation minerals and resident fluid. The type of wellbore fluid is water, CO2, or a mixture of the two depending on the well type—injection, monitoring, or production well. Although a water-filled wellbore is optimal for PN well logging, a CO2- filled wellbore does not adversely impact CO2 monitoring to a high degree if a sleeved-PN tool is used. As formation lithology types and water salinity influence inelastic and capture PN measurements differently, determining which PN log should be used for CO2 saturation analysis is essential. The impact of the shale volume and properties on the PN data is nonuniform, so this factor must also be carefully reviewed in conjunction with the lithology type. Furthermore, accurate estimation of oil and CO2 densities under downhole conditions minimizes the uncertainty of multiphase fluid saturation characterization. Finally, considering the effects of mineral alteration and formation dry-out is required when evaluating saturation in post-injection stages.

It is crucial to consider well- and formation- specific factors to ensure accurate monitoring of in-situ CO2 propagation and multiphase fluid volume variation with PN well logging. The best practices for PN well logging and data analysis were evaluated using a customized MCNP modeling technique. Furthermore, surveilling the behavior of injected CO2 on a well basis enables the optimization of CO2 injection parameters and the updating of reservoir models on a field-scale level.
Decarbonization of Gas Oil Separation Plants Through Automated Energy Balance
Authors: Alhamoud A. , Fallatah H. , Algady A.
Published: May 2024

In alignment with our commitment to decarbonization and sustainability, we prioritize energy optimization initiatives that continuously monitor and improve the energy efficiency of our assets. At Gas Oil Separation Plants, the primary assets identified as Significant Energy Users include multi-stage centrifugal pumps (utilized for water disposal and crude shipping) and centrifugal gas compressors. The energy consumption of these assets is contingent upon their optimal utilization, equipment performance, and settings A systematic data-driven energy balance using aggregated values is proposed as an effective way to monitor & optimize the performance of these assets, and linking of the energy consumption to actual production figures.

The energy balance is performed using available power meters or estimations based on first principles for assets without meters. Data is prepared in order to achieve adequate cleansing and time aggregated values are calculated per Significant Energy Users asset groups. The energy balance is then complemented with production values aggregates and KPls to relate actual consumption figures along with production records.

Aggregated values analysis provides a time-based approach to quantify deviations from optimum performance. Optimum performance for each facility depends on its design and particular configuration. The deviations can be due to a number of reasons such as operating more equipment than required for longer periods, equipment underperforming, non-optimum settings, instrumentation calibration requirements, etc. The periodic automated report of these deviations facilitates timely resolution and continuous usage of generated data for energy optimization.

The modeling tools used in this paper are self-service time-based data analytics solutions with built-in functions for modeling and prediction. It provides features to facilitate use case scalability across different facilities.
Enhancing Production in Carbonate Formations with Innovative Self-Supporting Lightweight Cement System to Isolate Water Zone Under Total Losses
Authors: Abdulqader Mustafa Sarbast , Imran Muhammad , Becharef Mohamed , Zanaty Omar El , Shahzad Kamil , Taher Sherwan
Published: May 2024

Addressing the compound issue of a placing a balanced cement plug to isolate the open hole section from 1026 m to 976 m in a workover well in northern Iraq. The Khurmala formation was experiencing total losses and increased water production issues. The plug also had to be accurately placed to avoid cementing the lower of perforation zone (956m - 965m). A cement slurry design had to be formulated to efficiently isolate the water zone under total losses.

Several fluid design approaches have been taken to design a successful slurry. First, to address the total losses condition of the open hole, the decision to use an 11 ppg slurry was mainly to reduce the hydrostatic pressure exerted by the cement column while introducing fluid loss control properties as well as optimizing the rheology. Furthermore, a specialized gelling agent was introduced to the design that enables the slurry develop a self-supporting characteristic as soon it is left in a static condition. As these were the key aspects of the design, more parameters and constraints that were identified and addressed will be discussed further in this paper.

As the job was executed, the success of the design was assessed according to industry standards. Initially contaminated cement was observed at surface while circulating out at the TOC indicating the presence of cement fluid at the intended interval. Subsequently, post the wait on cement period, the plug was tagged at the desired depth indicating that the water production zone has been successfully isolated in a single attempt, eliminating the need for excessive resources, solutions, time and cost that would otherwise be required for this kind of challenge and eventually the hydrocarbon production is increase significantly.

The novelty of this approach lies in designing a lightweight cement slurry with the key self-supporting characteristic while maintaining the required design parameters such API fluid loss, static gel strength, compressive strength development, and rheology.
Enhance the Transformation Effects of Hydraulic Fracturing in Casing Deformation Well
Authors: Zhang Shuo , Zhang Wei , Zeng Qijun , Jin Ningjing , Zhu Jianjun , He Zhenzhen
Published: May 2024

Casing deformation in shale gas wells poses a significant challenge to hydraulic fracturing operations, often leading to reduced efficiency and effectiveness in reservoir stimulation. This paper aims to enhance the transformation effects of hydraulic fracturing in wells afflicted by casing deformation through the introduction of novel techniques and materials. We present an integrated approach that includes the deployment of high expansion dissolvable plug tailored for restricted diameters, the use of spiral seal structures to ensure reliable anchoring within deformed wellbore sections. Finite element analysis and field trials are conducted to evaluate the performance of these solutions under varying downhole conditions. The outcomes demonstrate substantial improvements in the delivery and sustainability of fracturing pressures, leading to increased stimulated reservoir volumes and optimized hydrocarbon recovery rates. These results suggest that adopting such specialized interventions can significantly counteract the limitations imposed by casing deformations, thereby reviving the productivity of compromised wells and extending their operational lifespan.
Analysis of Minerals in Drilling Fluids Using Synergy in X-Ray Fluorescence and Fourier Transform Infrared Spectra Realized with Machine Learning
Authors: Atheaux I. , Medvedev A. , Makarychev-Mikhailov S.
Published: May 2024

Analysis of solid contents in drilling muds is part of the API mud testing protocol performed daily by the mud engineer during drilling operations. This is carried out with the laborious manual retort analysis where high-gravity solids (HGS) and low-gravity solids (LGS) are detected. With the vision to improve the process and potential toward online measurement, monitoring of HGS and LGS in water-based mud (WBM) using two fast and reliable analytical techniques, X-ray fluorescence (XRF) spectrometry and Fourier transform infrared (FTIR)-attenuated total reflection (ATR) spectroscopy, have been evaluated. While information on total LGS content in a drilling fluid is useful, understanding the LGS minerology is also undoubtedly valuable, particularly when reactive clays are present and wellbore stability and integrity are at risk. In the present work we describe the dataset of XRF and FTIR-ATR spectra of a series of multicomponent water-based drilling fluids loaded with up to eight dispersed minerals. The minerals were barite (HGS) and LGS as clays (bentonite, illite, and kaolinite), carbonates (calcite and dolomite) and siliceous minerals (quartz and soda feldspar). Machine-learning (ML) analysis techniques such as partial least squares (PLS) and advanced modern PLS methods were applied to XRF and FTIR combined data to analyse these complex multicomponent samples.

In this paper, a detailed discussion of the data workflows will cover the spectra preprocessing, ML algorithm selection and results on individual spectra, concatenated data, and data fusion. While quantification of barite (HGS) in drilling fluids with either XRF or FTIR was straightforward (the coefficient of determination, R2, at ~0.99), analysis of some LGS was more challenging. For example, the best soda feldspar and calcite PLS models based on FTIR spectra showed poor performance (R2 ~0.75 and ~0.48, respectively). Interestingly, PLS models based on different combinations of concatenated spectra (joined side-by-side) demonstrated even worse results compared to the single spectra models. Extensions of the PLS method designed to deal with multiblock datasets were then explored, and the sequential and orthogonalized PLS (SO-PLS) was found to be the best, realizing the synergy between spectrum types. SO-PLS models for calcite and soda feldspar gave R2 of 0.97 and 0.77, respectively. Detailed error analysis for all minerals is finally presented in the paper, with prediction errors varied from 1% for barite to 11% for soda feldspar.

The two spectrum types, when smartly processed together using data fusion and ML techniques, demonstrate synergy, and provide significantly better mineral quantification accuracy, achieving a comprehensive minerology analysis of solids in drilling fluid.
Numerical Investigation on Energy Loss Characteristics in Irregular Annulus Based on Entropy Production Method
Authors: Zhou Y. S. , Qu C. F. , Jiang L. , Zhang H. W. , Zhang X.B. , Huang Z. , Li J. P. , Zhou C. Y. , Cheng S. D. , Li Y.
Published: May 2024

The actual downhole annulus is irregular, a variable cross-section geometry, due to the difference between the diameter of tool joints or downhole tools and the inner pipes. With the increasing of well depth, inevitable energy loss caused by contraction or expansion geometry is high in irregular annular flow. However, the energy loss generation mechanism for such irregular annulus flow is still unclear. The entropy production theory is considered as an excellent method for energy loss analysis, which is widely used in fluid machinery flow field.

Therefore, the main purpose in this work is to reveal the energy loss generation mechanism caused by contraction and expansion geometry in irregular annulus based on entropy production method. In this paper, the spatial distribution of entropy production rate in irregular annular flow was depicted first. Then the inlet velocity and contraction-expansion ratio influence on different entropy production were discussed. Finally, we identified the high entropy production area and its main energy loss sources by quantitative analysis.

The results show that 1) The high entropy production was mainly occurred at the entrance, downstream of the variable cross-section structure and near the wall. The proportion of time-average entropy production rate was relatively small and can be ignored. 2) The main energy loss areas were in narrow annulus and downstream of the variable cross-section structure, which the entropy production portion was about 55.8%~62.0% and 23.4%~26.4% separately. The main energy loss were wall and turbulent entropy production in these two areas. 3) The energy loss generated in downstream of the variable cross-section in annulus was more than that in upstream.
Study of Surface Complexation Modeling on Low Salinity Polymer Flooding in High-Temperature High-Salinity Carbonate Reservoirs
Authors: Hassan Anas M. , Sebastian Anoo , Al-Shalabi Emad W. , Kamal Muhammad S. , Patil Shirish
Published: May 2024

The low salinity polymer (LSP) injection is a hybrid enhanced oil recovery (EOR) technique, which synergistically enhances the displacement and sweep efficiencies through compounding the advantages of low-salinity water (LSW) and polymer floodings (PF). While an appropriate LSP-flooding field-scale design typically requires a predictive mechanistic model for capturing the polymer-brine-rock (PBR) interactions, few studies have focused on this issue till date. Therefore, the present study investigates the impact of water chemistry on polymer behavior in porous media using a surface complexation model (SCM), with the purpose of refining our understanding of the PBR-system. In particular, this work examines the effect of salinity and hardness on polymer viscosity and adsorption in dolomite formations during LSP-injection with the use of our in-house developed coupled MRST-IPHREEQC simulator. Hence, to comprehensively capture the geochemistry of the LSP process, the coupled MRST-IPHREEQC simulator included the chemical reactions, such as aqueous, mineral dissolution and/or precipitation, along with the surface complexation reactions.

The findings of this study showed polymer viscosity losses of 82% and 63% for the 10-times spiked salinity (6230 ppm) and 10-times spiked hardness (110 ppm) cases, respectively. Thus, the base case low-salinity (LS) brine of 623 ppm was more effective in reducing the risk of polymer viscosity loss for the dolomite model (i.e., viscosity loss of 55%). The polymer viscosity losses calculated for the various potential determining ions (PDIs) concentrations of 10-times spiked Mg2+ (40 ppm) and 2-times spiked SO42- (156 ppm) were 61%, and 46%, respectively. Moreover, investigating the impact of salinity on polymer adsorption revealed that dynamic polymer adsorption increased from 53 μg/g-rock to 68 mg/g-rock and 64 mg/g-rock, when the salinity and hardness were increased from the base case (623 ppm) to 10-times spiked salinity and 10-times spiked hardness cases, respectively. Furthermore, the analysis showed that the 10-times spiked magnesium case exhibited higher polymer adsorption (87 μg/g-rock) compared to the 2-times spiked sulfate case (64 mg/g-rock), which is related to the formation of Mg-polymer surface complexes as a result of surface complexation processes between polymer molecules and magnesium surface species at the surface of dolomite rock. Overall, the surface complexation model has demonstrated that during LSP-injection, the stability of the water-film is enhanced, suggesting a significant alteration in wettability towards a more water-wetting state. This wettability alteration plays a crucial role in increasing oil production. Consequently, our findings underscore the effectiveness of LSP-flooding in enhancing oil recovery processes by modifying the wettability of the reservoir rock surfaces, leading to a more efficient displacement of oil.
A Method for Predicting Formation Pore Pressure in Carbonate Rocks
Authors: Tao Zhenyu , Liu Yuhan , Ye Yuguang , Fan Honghai , Sun Lewang , Shang Heya , Wang Lihao
Published: May 2024

Formation pore pressure refers to the pressure of the pore and the fluid in it, which is an important parameter in drilling engineering, related to well depth structure design, drilling fluid preparation, and casing matching. Accurately predicting formation pore pressure helps to reduce drilling accidents and achieve safe drilling. Due to the complexity of the causes of abnormal pressure in carbonate rock formations, it is difficult to predict the formation pore pressure. Taking Block M in Qaidam Basin of Qinghai Oilfield in China as an example, this paper proposes a prediction method for formation pore pressure in carbonate rock formations based on analyzing the causes of abnormal pressure. Firstly, based on core analysis and well-log interpretation, this paper analyzes the causes of abnormal pressure in Block M; According to the causes of abnormal pressure, the Fan comprehensive interpretation method is selected as the calculation method for the formation pore pressure. The model is modified based on well-log data and experimental data, and the BP neural network is used to correct the prediction error. Based on this model, the formation pore pressure of two wells is predicted. Compared with the measured points, the error is less than 5%, which meets the engineering requirements.
Pore-Scale Modeling of Hydrogen-Brine Relative Permeability in Underground Hydrogen Storage
Authors: Dorhjie D. B. , Cheremisin A.
Published: May 2024

Hydrogen is poised to become one of the most promising alternative clean sources of energy for climate change mitigation. The development of a sustainable hydrogen economy depends on the global implementation of safe and economically feasible intersessional hydrogen storage and recovery. However, the current body of literature lacks comprehensive numerical characterization of the multiphase flow of hydrogen-brine and how geological parameters at the pore scale influence the multiphase flow. This study presents a pore network simulation of hydrogen-brine and cushion gas-brine relative permeabilities. Initially, the generated pore network model was validated against the characteristics of the core sample, such as porosity, permeability, and pore size distribution. In addition, the model was adapted to replicate the results of the drainage capillary pressure curves and relative permeability curves observed in the laboratory experiment. Furthermore, a sensitivity analysis was conducted to quantify the effects of fluid and rock properties on the relative permeabilities of the fluids. The results indicate that the capillary pressure and the relative permeability of the hydrogen and brine are sensitive to the distribution of the surface contact angle. The relative permeability of hydrogen phase decreases as the frequency of pores with stronger water-wet contact angle values increases. The relative permeability endpoint (residual saturation) was also significantly influenced by pore and throat shape, pore and throat size distribution, and pore connectivity. Simulations of different cushion gases revealed that the relative permeabilities of CH4 and N2 are similar to hydrogen. This research offers a comprehensive pore-scale prediction of the relative permeability of hydrogen and brine systems and presents the parameters and cushion gases to consider in the selection of geological storage sites for hydrogen storage.
Application of NMR Relaxometry in Petrophysical Properties Determination and Pore Structure Characterization for Clastic and Carbonate Rocks
Authors: Samokhvalov N. , Kovalenko K. , Skibitskaya N. , Ponomarenko O. , Zaripova L. , Muminov A.
Published: May 2024

This paper discusses the use of Nuclear Magnetic Resonance (NMR) relaxometry to effectively determine the porosity and irreducible water saturation of rocks. The rapidity, efficiency and lack of influence on the core sample integrity actualizes the development of methodological approaches for experiment procedures and interpretation of measurement results in order to increase the information content of the method [24].

The paper presents the results of NMR investigation of clastic and carbonate rocks at full water saturation, irreducible water saturation and residual gas saturation, trapped during spontaneous imbibition. The first section of the paper presents possibility of NMR to evaluate separated distribution of pores and throats by size, which provides characterization of pore space structure of the reservoir and distribution of fluids by different types and the degree of bonding with rock surface. The second section presents results of suggested "subtractive distributions" of transverse relaxation time (T2) for characterizing various elements of the pore space and obtaining their distributions according to the volume ratio. The third section presents technique for determination of the irreducible water saturation and gas saturation trapped during spontaneous imbibition based on the T2 cutoffs. And fourth section presents review and consideration regarding possibilities and limitations of the NMR method in determination throat size distributions and capillary pressure curves modeling. In the conclusion the future research directions from current conducted researches have been suggested. The matters concerned in this research provides an insight into mechanism of fluid displacement through the drainage and spontaneous imbibition processes. Suggested techniques of investigations and data interpretation intended to improve understanding of rock pore space structure and reservoir properties.
Upstream Data Project Portfolio Benchmarking as a Novel Approach for Strategy and Value Realization
Authors: Mohd Nasir Amir Ikhwan Haniff , Chan W.
Published: May 2024

PETRONAS Upstream has been executing multiple data projects each year with different level of complexity and risk comprising of a myriad of project categories such as data delivery, stranded data recovery, system development and data governance. The imperative requirement in delivering the projects to ensure business success and continuity calls for a strategic decision to produce and design a methodology to benchmark the projects for a comprehensive data portfolio management, which is crucial for maximizing the value of data projects to the organization. This paper outlines a novel approach on how Upstream Data innovate a portfolio benchmarking process to quantitatively assess the complexity of the projects by utilizing a modified Diamond Framework Model referred to as the Pentagon Model with the following objectives in mind: Improve resource planning and allocation efficiencyConduct a thorough project risk assessment and value realizationAnalyze project benefits and assess possible business impactIdentify appropriate project management approaches and styles
Implementation of Machine Learning Approach in Pore Size Evaluation Workflows for Carbonate Reservoirs
Authors: Alward W. , Al-Jubouri M.
Published: May 2024

The petrophysical evaluation of carbonate reservoirs presents a significant challenge due to complex diagenetic processes that alter reservoir properties. Advanced log measurements, such as NMR T2 relaxation time and borehole images, are often necessary to evaluate the carbonate pore systems (micro, meso, and macro pores), and permeability and infer the impact of diagenesis on reservoir properties. The absence of these measurements may lead to inappropriate estimation of reserves and inadequate development strategies. To address this challenge, we propose a novel interpretation method that utilizes machine learning algorithms to perform carbonate porosity partitioning (micro, meso, and macro) using standard log measurements (e.g., resistivity, density, neutron, sonic, and gamma-ray). We trained the machine learning model in key wells with NMR and/or borehole images to establish relationships between standard logs and carbonate pore partitions. Subsequently, we applied the model to other wells to predict the target pore volumes. Standard ML model workflow (data cleaning, feature engineering, train/split, hyperparameter tuning) was followed. We present a comprehensive workflow for accurate evaluation and characterization of carbonate reservoirs where NMR measurements are not available. We successfully applied this workflow to datasets from heterogeneous carbonate reservoirs in South Iraq to obtain reliable carbonate pore partitions. These pore volumes were then used to estimate permeability and variable cementation exponent to improve water saturation and perform carbonate rock typing. Our proposed methodology provides a reliable and efficient approach (if applied with domain knowledge and reservoir considerations) for the petrophysical evaluation of inter- and intragranular, vuggy carbonate reservoirs, particularly in cases where advanced log measurements are not available, overcoming challenges with the traditional interpretation methods in such complex reservoirs.
Phased Installation of Fixed Offshore Wellhead Platforms for Drilling and Production in Shallow Water Risky Marginal Fields with Moderate Environment
Authors: Chatterjee Prabir Kumar
Published: May 2024

This paper proposes a minimum structure to drill and appraise four oil/gas wells without installing a structural jacket. A structural template with conductor guides will be installed on seabed. The well conductors may be driven into the seabed by a hammer fitted to the jack-up rig-based crane. The conductors will support a small, prefabricated two-level deck (9m × 12m). The template is supported by customized mudmats to withstand the environmental loads without piled foundation. In case of a positive drilling outcome, a riser and a pipeline will be added to connect with the nearest subsea/onshore tie-in point to carry out well testing by flowing the wells. Based on the outcome of a prolonged well testing, installation of the remaining facilities will be undertaken. In Phase-2, a structural jacket will join the template and piles will be driven through the legs. The deck of the second phase will have internal opening to clear the existing topside (installed in Phase-1) during installation. The existing and the new decks will be joined at offshore. The platform has a provision for two future wells.

Numerical studies show that the Phase-1 structure can withstand omnidirectional environmental forces due to 10.4m high waves and Phase-2 structure can withstand 15.4m waves at 35m water depth. Structural design is performed using API RP2A working stress design method. The results show adequacy of the structure with required minimum reserve strength and prove that large amount of initial CAPEX can be avoided by carrying out well appraisal before installing full production facilities.
Preparation and Mechanism Study of Ternary Resin-Nano Silica Copolymer Lost Circulation Additive for Oil-Based Drilling Fluid
Authors: Dai Liyao , Sun Jinsheng , Lv Kaihe , Bai Yingrui , Li Mei-Chun
Published: May 2024

Due to the development of shale bedding and micro-fractures, it is very easy to induce complex downhole accidents such as leakage during the drilling of horizontal Wells, and the leakage of oil-based drilling fluid is serious, resulting in great economic losses. Aiming at the problems of poor compatibility and insufficient temperature resistance between chemical plugging materials and oil-based drilling fluids. In this paper, butyl acrylate, octadecyl methacrylate and sodium p-styrene sulfonate were selected as the copolymer, dibenzoyl peroxide as the initiator, divinylbenzene as the crosslinking agent, nano-silica as the toughening agent, and water as the dispersed phase. A ternary resin-nano silica copolymer lost circulation additive was prepared by suspension polymerization. The results showed that the molecular structure test of the resin lost circulation additive indicated that the unsaturated groups were grafted and the interpenetrating three-dimensional mesh structure was formed, with oil-absorbing and swelling properties at high temperatures and good mating properties. Under the condition of 140 ℃, the sealing experiment was carried out on the sand plate with a pore size of 1 mm, and the pressure capacity was up to 10.6 MPa. The particles compact and seal the leaking strata by deformation compaction and filling action. Compared with conventional plugging materials, resin lost circulation additive has good thermal stability and self-adaptability, easy to enter the pore space, micro-fracture, oil-based drilling fluid loss is effectively reduced.
Agnostic Tooling: A Modular Approach to Producing Fields Tooling Needs
Authors: Bouillouta F. , Narozanski M. , Yuill L. , Silva A.
Published: May 2024

The aim of this abstract is to demonstrate an innovative methodology used to maximize tools adaptability reducing risk exposure and cost with an attractive lead time. Furthermore, it will highlight the past project successes and lessons learned. A key challenge within life of field operations is securing tooling sets across different well types from various original equipment manufacturer (OEM), a timely and costly process. Recognizing that despite different OEMs, there are common mating features for tooling to interface with, the "Swiss Army Knife" of agnostic tools targets an operator’s total requirement with the minimum number of tools needed. This innovative approach to tooling uses a modular design, whereby tooling can be adapted to multiple well types and the functionality targeted to specific operational requirements.

The methodology presented reduces the quantity of tools required, improves capability, and lowers CO2 emissions. By design, the agnostic tools are not limited by the original OEM specifications as they can be simplified and modularized resulting in an efficient and economically beneficial process. For example, one area of simplification is to use a standardized guiding and landing of the intervention tooling on the subsea equipment.

In addition, given the operational challenges when planning offshore campaigns on multiple wells, working with just one supplier of the intervention tooling package, allows for more flexibility in case re-prioritizations or re-scheduling shall be required. One key area of success for this approach is in support of decommissioning offshore oil and gas infrastructure which will hit an average of US$15 billion a year to peak in 2035 and is the subject of increasing regulation to comply with end-of-life plug-and-abandonment. A recent case study for a multi-OEM well P&A campaign in Brazil benefited greatly from this approach; the modular design reducing the total number of tools from 62 to 23 within a 12-month lead-time.

The novelty in agnostic tooling is the modular approach to tooling from different OEMs subsea equipment, reducing the total number of tools needed via tooling standardization and therefore the overall campaign cost with a single point of contact.
Influencing Factors of Breakdown Pressure in the Mahu Conglomerate Reservoir under Perforation Conditions
Authors: Jia Wenting , Mou Jianye , Li Xiaowei , Wang Xinliang , Zhang Shicheng , Wang Lifeng , Xu Yajun
Published: May 2024

The Mahu Oilfield in Xinjiang, China, is the world’s largest conglomerate oilfield with massive geological reserves. In the multi-cluster staged of horizontal well fracturing, the breakdown pressure is high, and the fracture is difficult to initiate. Therefore, lowering the breakdown pressure is the key to hydraulic fracturing safely and efficiently. In this paper, we first develop a new water jetting experimental apparatus that can adjust perforation parameters to simulate spiral perforation in the oil field. It consists of perforation angle, position, and depth. The researchers went to the Mahu area for geological investigation and excavated conglomerate outcrops from the Baikouquan formation to conduct true triaxial hydraulic fracturing physical simulation experiments. The research results indicate that water jetting perforation can reduce the breakdown pressure by 6 MPa under immutable in-situ stress magnitude and distribution. It is easier to initiate when the angle between the perforation tunnel and the maximum horizontal principal stress is 0°, with the lowest breakdown pressure. If natural fractures are developed near the perforation hole, the communication between the perforation tunnel and the natural fractures prominently reduces the difficulty of fracture initiation. After fracturing, it is easy to form complex multi-fractures with high tortuosity and surface roughness, and the breakdown pressure declines sharply. The research results provide theoretical support for reducing the breakdown pressure in conglomerate reservoirs with strong heterogeneity.