bluuebunny/crossref_metadata_2025 huggingface dataset:
Graphene Nanoplatelets for Extended Lifetime of Scale Inhibitor Squeeze Treatment in High Temperature Reservoir
Authors: Zainal Suzalina , Razali Norzafirah , Rodzali Mohamad Azmeer
Published: October 2023

Scale inhibitor squeeze (SISQ) treatment is an established method for offshore fields which allows an extended effectiveness of the scale inhibitors in preventing scale deposition over time. Some of the main issues in SISQ campaign is the short squeeze lifetime being less than 1 year which may be contributed by operational and well integrity issues as well as ineffective design of the pre-flush system.

This study proposed graphene nanoplatelets as pre-flush system to extend the lifetime of a conventional scale inhibitor squeeze treatment. This carbon-based nanomaterial known for its high specific surface area provided an excellent pre-coating on the rock matrix, allowing an enhanced adsorption of the phosphonate-based scale inhibitor.

Special attention was given to the study on stability of the graphene nanoplatelets (GNP) in high divalent injection water and its functionalization with biopolymer to provide good dispersibility in the seawater at high temperature condition. This paper focuses on the compatibility evaluations of GNP in seawater, its dispersion and thermal stability assessment up to 96oC temperature, followed by an innovative static adsorption experiment using Berea crushed cores which served to establish the improvement in scale inhibitor adsorption at different GNP concentrations. For in-depth performance evaluations in downhole porous media, injectivity and adsorption-desorption scale squeeze treatment coreflooding experiments using Berea and reservoir native cores at high temperature conditions were then tmperformed. Finally, prediction on the field squeeze lifetime were simulated using Place-iT™ software.

Results shown that the scale inhibitor's adsorption increased by more than 100% when 200 ppm of modified GNP was used as pre-flush compared to conventional pre-flush system. Good injectivity profiles, showing Residual Resistance Factor (RRF) of less than 3, coupled with slower desorption rate of scale inhibitor were observed from the coreflooding results. The simulated scale squeeze lifetime improved up to additional 14 months compared to baseline. Graphene nanoplatelets have demonstrated its versatility as nanocoating agent in enhancing scale inhibitor squeeze lifetime, extending its application as downhole high temperature production enhancement chemical.
Kuwaiti Carbonate Reservoir Oil Recovery Prediction Through Static Wettability Contact Angle Using Machine Learning Modeling
Authors: Al-Sayegh Saleh , Flori Ralph , Al-Bazzaz Waleed Hussien , Al-Saedi Hasan , Al-Kaouri Mostafa , Qubian Ali
Published: October 2023

The objective of this study is to predict EOR efficiencies through static wettability contact angle measurement by Machine Learning (ML) modeling. Unlike conventional methods of measuring static wettability contact angle, the unconventional digital static wettability contact angle is captured and measured, then (ML) modeled in order to forecast the recovery based on wettability distribution phenomenon. Due to success in big data collection from reservoir imaging samples, this study applies data science lifecycle logic and utilizes Machine Learning (ML) models that can predict the recovery through wettability contact angles and thus identify the treatment of oil recovery for a candidate reservoir.

Using developed morphological driven pixel-data and transformed numerical wettability contact angle data are acquired from Scanning Electron Microscope Backscattered Electron (SEM-BSE) for 27 fresh core samples from top to bottom of the reservoir. These samples are properly sequenced and then images are selected. Big data from imaging technology have been processed in a manner to train, and test the model accuracy. Applied Data Science Lifecycle technique, such as data mining, is utilized. Data Exploration Analysis (DEA) is implemented to understand and review data distribution as well as relationships among input features. Different supervised ML models to predict recovery are utilized and an optimal model is identified with an acceptable accuracy. The selected prediction model is applied to model the optimal recovery practice.

Extreme Gradient Boosting (XGBoost) algorithm is utilized and found as a best-fit model for this Kuwaiti reservoir case practice. Moreover, decision tree and Artificial Neural Network (ANN) models could provide acceptable accuracy. Other supervised learning models were attempted and were not promising to provide feasible accuracy for this carbonate reservoir.

The novel of this unique solution of the data-driven ML model is to predict recovery based on static wettability contact angles (θ°). The static wettability contact angles (θ°) and pore morphological features introduce an insights method to support reservoir engineers in making value-added decisions on production mechanisms and hydrocarbon recovery for their reservoirs. Hence, it improves the field development strategy.
Optimizing the Carbon Footprint of Polymer Injection Utilizing a Deep Learning Log Interpretation Framework
Authors: Katterbauer Klemens , Al Shehri Abdallah , Hassan Saleh , Yousef Ali
Published: October 2023

The world of energy industries is exhibiting tremendous efforts to ensure the sustainability of its operations and reduce its carbon footprint. These efforts include optimizing field operations to be more sustainable while maintaining production levels. The 4th Industrial Revolution is having enormous impact on the oil and gas industry, also allowing better analysis of carbon footprint reduction opportunities. Modern logging technologies are able to accurately characterize the formation and measure its production behavior. Polymer injection technologies have the potential to significantly reduce water cut, thereby helping to optimize the carbon footprint. We evaluated the impact of various polymer injection strategies on the Volve field with several production and injection wells to simulate the impact of injecting polymers on the fluid production rates. The injection of polymers helps in reducing the water production rates from the reservoir, thereby reducing the carbon footprint related to the handling of the produced water and injection of water. Various scenarios were evaluated in order to determine the overall impact on carbon emissions and based on a probability-likelihood framework the overall carbon footprint was determined. While the optimal injection strategy may depend on various factors, polymers demonstrate the ability to reduce significantly the overall carbon footprint while increasing hydrocarbon production.
Learning from Water Injection Pilot in a Low Permeability Reservoir Developed with Hydraulically Fractured Horizontal Wells – ABH Field Case Study
Authors: Singh Ranjeet , Agarwal Prashant , Saurav _ , Gupta Sumit , Mandapati Suresh Kumar
Published: October 2023

Aishwariya Barmer Hill (ABH) is a Porcellanite oil reservoir located in the northern part of Barmer Basin in India. The formation has low permeability of ~1mD, an average porosity of 25% and has in-situ oil viscosity of ~3 cP. The ABH field has been developed with long horizontal wells with multistage hydraulic fracturing under depletion drive. The current estimated RF is 10-12% on depletion drive. To improve the RF, water flood was evaluated as the next stage of development. This paper discusses the results of water injection pilot within a complex setting with hydraulically fractured producer (observation) wells and impact of injection below and above frac pressure.

Two short term injectivity tests and one long term injection pilot have been conducted in ABH field. Concepts like injection above and below frac pressure and injection in a hydraulic fractured well and a non-hydraulic fractured well were tested.

The long-term injection pilot comprised of a vertical injector and two hydraulically fractured horizontal producers on it's either side. As the injection pressure was above frac pressure, data like time lapse Pressure Fall Offs (PFOs) was acquired to understand waterflood induced frac parameters. Production logging and bottom-hole pressure surveys were also conducted to understand injection profiles.

Minimal injectivity was attained below frac pressure but good injectivity with sustained rate was observed above it. PTA analysis shows that fractures are induced due to water injection and time lapsed PFOs were analyzed to estimate the induced fracture parameters. Some unique signature of frac closure was also observed in PTA. Increase in water cut of one of the producer well was observed, however most of the injected water was getting imbibed into the reservoir. Role of injection water quality was also evaluated which may cause drop in injectivity and continuous frac growth. Numerical simulation was carried out to history match the observed injection performance. This indicated changes in effective permeability during injection and shut-in periods.

Careful consideration of injection pressure, well design and pattern selection is critical for designing water flood in a low permeability reservoir with hydraulically fractured wells and this pilot was able to answer many questions related to it. The pilot suggested that below frac pressure injection may be required in on-trend well pattern. Poor quality injection water can cause growth of induced fracture. Response time on producer is a key consideration impacting project economics. Improving recovery from tight field development is a key area of focus and ABH pilot results will help to understand /solve some of the key considerations related to it.
Physical Simulation and Improved Numerical Simulation Method of Non-Condensable Gas Co-Injection in SAGD Process
Authors: Liang Guangyue , Liu Yang , Xie Qian , Xia Zhaohui , Liu Shangqi , Zhou Jiuning , Bao Yu
Published: October 2023

There are great differences about the distribution of non-condensable gas (NCG) in steam chamber between field observations and numerical simulations. Field observations show that the process could reduce steam consumption significantly but no evidence of impairment to oil production especially in mid to late SAGD life. However, this point isn't consistent with current numerical simulations. Therefore, this paper presents an improved numerical simulation method of non-condensable gas co-injection to validate the physical simulation results.

Solubility experiments of methane, nitrogen and carbon dioxide in oil phase at different pressure and temperature were conducted to analyze the interface properties, and 1D core experiments to understand the displacement characteristics. On the basis, 3D physical simulations were conducted with each gas in SAGD process. These results were inconsistent with conventional numerical simulations. In order to narrow the gap, sensitivity analysis was conducted by using CMG STARS software considering different grid size, solubility or K-value in oil and water phase, rate-dependent dissolution and ex-solution of NCG in oil. Non-equilibrium dissolution and ex-solution behavior and reaction equations were incorporated to successfully improve the numerical simulation results.

The experimental tests indicate that the solubility and compressibility of methane fall in between nitrogen and carbon dioxide. Then 3D visualized physical simulations with methane, nitrogen or flue gas co-injection and shale interlayer existence were conducted to analyze the law of NCG distribution, steam chamber growth and SAGD performance. NCG tends to accumulate at the top rather than the drainage edge of steam chamber, decrease the temperature of reservoir top by about 30°C, reduce heat loss to the cap rock and improve steam to oil ratio (SOR). Compared with other gases, carbon dioxide decrease oil viscosity most and achieve higher displacement efficiency. Also, it succeeds in improving the flow characteristics of steam chamber front, maintaining pressure, stabilizing or slightly lowering oil production and reducing steam injection significantly by co-injection with these NCG at increasing proportion, when steam chamber reaches the top of reservoir. Particularly, NCG can penetrate thin shale interlayer, allow steam passing through and help accelerate vertical steam chamber growth. Finally, the parameters were optimized using improved field-scale model such as solvent type, co-injection concentrations and timing, etc.

The novelty of this paper is successfully revealing NCG distribution law in steam chamber by visualized physical simulations. Particularly, it also captures the phenomenon that the existence of NCG can help steam chamber penetrate the shale interlayer. The findings narrow the gap among field observations, physical and numerical simulation and can guide NCG co-injection optimization.
Simple Sidetrack to Remediate Wells with Mechanical Downhole Problem: A Case Study of Open Hole Gravel Pack Well Intervention
Authors: Pramesty Denissa Pramesty , Monhendri Riko Monhendri , Pambudi Deny Eva Tri , Wijanarko Iwan Wijanarko
Published: October 2023

DF field is first steam flood project in Indonesia and one of the biggest steam flood oil fields in the world. The field has shallow reservoir and unconsolidated sand formation. There are several oil well completion types but majority production wells are open hole completion with gravel pack as sand control. Over time, some wells have sand control equipment failures and result unwanted formation sand production that cause oil production restriction and artificial lift failures. To remediate the problem, well intervention (which named as revise liner) jobs are required to pull out failed screen liner then replace with the new one. Basic procedure consists of pull-out existing pump, pull out lead seal, wash over the screen to remove gravel pack sand and continue with screen liner retrieval. Reaming job is required to clean out the open hole section before running new screen assembly and be gravel packed. The job will be ended by running in hole new pump.

However, several workover jobs could not be completed as planned due to downhole mechanical problems as results of aging wells and steam injection factors. In 2022, 7 of 23 screen replacement jobs were unsuccessful and majority due to failure to wash-over and recover old screens. A common solution to recover production from these problem wells is to plug & abandon the failed wells and drill new replacement wells. Even that so, this solution required significant time and cost that impede project economic.

Increasing number of loss oil production (LOP) due to sand control failure has triggered team to identify alternative solutions that economically feasible. This aligned with management strategy to increase oil production by minimizing LOP. Analyzing several alternatives, team came up with an idea to recover the screen by cutting it above free point at open hole section. Having sufficient open hole section below casing shoe will allow reaming job to open hole section in adjacent to existing hole.

Having conducted thorough risk assessment, team decided to execute first trial. The first job was deemed successful as it was able to reach target depth similar to existing hole. Screen liner assembly can be installed, and gravel sand can be packed without significant issue. This successful trial has encouraged the team to execute more wells with some refined procedure based on lessons learned from the first well. As of to date, total 3 wells have been completed successfully using this new method. Gravel pack logging also confirmed that gravel pack quality was not compromised.

This new practice has now become new method to recover production on wells having mechanical down hole problem in DF field. This practice is part of revise liner job conducted by workover rig with lower cost compared to conventional side track or drilling new wells.
Study on Continuous Monitoring Technology of Fiber-Optic Production Profiling
Authors: Xu Jianguo , Yang Qinghai , Sun Wei , Duan Yongwei , Huang Hui , Liu Yazhen , Xuan Gaoliang , Xu Gege
Published: October 2023

At present, the distributed fiber-optic production profiling testing technology mainly adopts the permanent casing and coiled tubing well running process, which is difficult to construct and the operating cost is high, making it impossible to be applied in scale. Moreover, it can only be carried out in short-term and single test, and cannot continuously monitor the dynamic changes of oil well production for a long time.

In this paper, a technology of continuous monitoring of production profile by optical fiber is proposed. The optical cable is bundled outside the oil pipe in the production well, and is lowered below the production layer. After the normal production of the well, multiple DTS sensor logging can be carried out according to the production demand to get the contribution rate of each layer and the dynamic change of production in the whole well. This technology has the characteristics of mature well-entering method, wide range of applicable well types, low risk and cost, and capable of long-term continuous monitoring.

This technology has been successfully applied in one production well in Jilin Oilfield. The target depth range of the test well was 586.8-639m, and the cable was run down the string in just 2.5 hours. 6 hours of shut-in temperature data was taken after completion; 8.5 hours of operating well temperature data was taken after normal production. Based on the fiber-optic logging DTS data, the reservoir-wellbore coupling model was established, and the model was inverted to obtain the production profile. Under the well opening production system, the production contribution of the 586.8-588.6m, 595-603m, 608-613m, 617.2-625.6m and 632-639m segments was 6.05%, 22.18%, 24.62%, 26.74% and 20.41%, respectively. Through optical fiber logging, the contribution of small layers in this well was obtained, which provided the data basis for reservoir analysis and development strategy adjustment. Since the cable is permanent, continuous monitoring can be carried out according to the development needs to understand the dynamic changes in the production of each small layer.

The technology has been proven to be feasible in vertical wells, and further optimization and improvement can make it possible to be used to monitor the production profile of horizontal wells, which changes the situation of the lack of low-cost and effective production profile testing technology of horizontal Wells.
Pore-Network Simulations of Gas-Water Two Phases Flow in Organic-Rich and Inorganic-Rich Shale
Authors: Wang Yong , Zhou Houjie , Cai Jingshun , Zhao Yulong , Zheng Jian , Zhou Hao , Zhang Tao , Tian Hongzhao
Published: October 2023

Focused ion beam scanning electron microscopy (FIB-SEM) is an effective method to investigate the pore structure and gas flow in shale. Insufficient investigations have been carried out with regard to the distinctions between the inorganic-rich and organic-rich samples in the flow simulation. In this work, we selected an organic-rich sample and an inorganic-rich sample for high-resolution three-dimensional imaging, and the organic pores and inorganic pores were effectively extracted using an improved digital rock processing method. Subsequently, the pore network model (PNM) of the two samples were generated separately. Finally, the pore network simulation method was introduced to calculate the flow capacity of the two samples. Data analysis shows that the inorganic-rich sample have a higher pore radius and throat radius and a larger shape factor, with more irregular pores. While the organic-rich sample have a higher average coordination number and better connectivity. The absolute permeability of the inorganic-rich sample is larger, at 1.46 × 10−7μm2, while that of the organic-rich sample is 1.05 × 10−7μm2. The capillary pressure curve of the inorganic-rich sample is lower than that of the organic-rich sample, exhibiting a lower drainage pressure PT and a longer liquid-invasion segment. Compared to previous pore network flow simulation methods, we set a uniform gas-wet surface with an advanced angle of 100-110° for the organic-rich sample, and an advanced angle of 20-30° for the inorganic-rich sample. Forced water injection was used to simulate the water (fracturing fluid) injection process in the organic-rich sample. Due to the hydrophobicity of the pores, the gas flow capacity during water injection was quite poor, but it was improved during drainage process. In contrast, due to the hydrophilic of the inorganic pores, the inorganic-rich sample exhibited spontaneous water imbibition during the water injection process. However, the inorganic-rich sample demonstrated higher residual gas saturation during the drainage process, which indicates that fracturing fluid flowback in inorganic pores is more difficult. This work emphasizes the importance of studying the real pore structure of inorganic pores in FIB-SEM experiments, which provides fundamental insights for the description of shale gas reservoirs and the simulation of gas-water two phase flow.
Gas/Water Transient Rate Analysis and Parameters Evaluation by Integrating Pseudopressure-Based Approach with Deep-Learning Method
Authors: Wang Junlei
Published: October 2023

Traditional transient rate analysis (RTA) based on single-phase flow equation has been limited to two-phase gas/water flow case. The primary complication associated with the adaptation of these single-phase solutions to wells exhibiting two-phase flow is the significant difference of gas/water PVT properties and the interaction between pressure and saturation during depletion process. As a result, the material-balance time based on single-phase assumption is not practical for analyzing two-phase flow from gas wells with gas/water flow characteristics. Meanwhile, there is still a lack of an automatic interpretation model on unknown parameters through history matching with measured production data, which increases RTA application threshold in the field of multiphase production data analysis.

This work presents an integrated method of forward modeling of production performance and inverse interpretation of unknown parameters in the depletion-driven reservoirs. In the forward part, the gas/water-phase integral transformations including pseudopressure and beta factor are proposed to handle the two-phase nonlinearities in the governing flow equations of gas and water phases. The rescaled well-performance equations subject to variable operating conditions are presented through integrating the existing single-phase liquid formations with Duhamel convolution. The normalized gas/water-phase pseudopressure and material-balance pseudotime are introduced to meet the benchmark requirement of using single-phase liquid type curves. In the inverse part, an automatic interpretation model of gas/water RTA is established based on one-dimensional convolutional neural network (CNN). CNN-based proxy model is built through training large synthetic data set from forward model. Automatic inversion of the parameters is completed by minimizing the fitness function from the loss between proxy model and measured data with the help of optimization-based algorithm. The new method is validated against numerical simulation, covering a wide range of fluid properties and operation constraints.
Surfactants Structured by Nanoparticles to Stabilize CO2 Foam at High Temperature
Authors: Karadkar Prasad , Ali Shahid , Shehri Tamim , Harbi Bader , Alsakkaf Mohammed , Mansha Muhammad , Khan Safyan
Published: October 2023

Foamed fracturing fluids offer an attractive alternative over conventional stimulation fluids, particularly in water-sensitive formations, to shorten the flowback period and energize the created fracture geometry. The thermal stability of foam at high temperatures is one of the main challenges. The gas-liquid interface of foam tends to collapse with temperature. In this paper, CO2 foam stability is enhanced by nanoparticles structurally supporting foaming agents at high temperature.

Nanoparticles (NPs) have a tendency to stabilize foam formulations under harsh conditions of temperature and salinity. In this study, different sizes of SiO2 NPs (7 nm, 30 nm) were utilized to enhance the stability of CO2 foam. The NPs were characterized by various techniques such as XRD, TEM, DLS, and BET surface area measurements. The foaming characteristics of various formulations were analyzed by a dynamic foam analyzer (DFA-100), respectively. Rheological properties of CO2-based foams were measured by circulating flow loop foam rheometer at high temperature (250 °F) and shear rate up to 500 1/s.

CO2 foam stability is enhanced by optimizing the concentrations of CTAB surfactant and silica nanoparticles at high temperature. According to XRD findings, CS-7 and CS-30 are amorphous materials with hexagonal crystal structure. The average diameter of CS-7 and CS-30 silica NPs, as shown by FETEM images, is 12 nm and 25 nm, respectively. CS-7 has a surface area (SBET) that is 2.27 times more than CS-30 sample. CS-7 silica NPs were confirmed to have a more uniform shape, a smaller particle size, and a larger surface area based on these findings. Both CS-7 NPs and the CS-7+CTAB formulation have zeta potential values of -36.9 and 42.1 mV, which support the stability of the foamed colloidal suspension and the development of a densely packed particle arrangement at the liquid/gas interface, respectively. The foam analysis results demonstrate that adding CS-7 silica nanoparticles (0.005 weight percent) to a CO2-based formulation increases foam stability by up to 12%, demonstrating the ability of nanoparticles to stabilize foam formulations. The NPs stabilized CO2 foamed fluids’ rheological characteristics exhibited 12 cp at 100 1/s utilizing water as the external phase at 2000 pressure and 250°F.

Maintaining the stability of CO2 foam was a challenging task, especially at high temperatures. The stability of CO2 foam greatly depends upon the optimum hydrophilic-lipophilic balance (HLB) of surfactants. This was achieved by optimizing various formulations using suitable CTAB surfactant and silica NPs to overcome water drainage, CO2 gas diffusion rate, and rupturing of foam at high temperatures.
Investigating Pore Body, Pore Throat, Nano-Pore Wettability Preference in Several Unconventional Kuwaiti Carbonate Reservoirs
Authors: Al-Sayegh Saleh , Flori Ralph E. , Alajaj Hussain , Al-Bazzaz Waleed Hussien
Published: October 2023

This study will investigate measuring the wettability contact angles of native unconventional tight carbonate as well as other unconventional pore system reservoir samples that hosts varied pore shapes and subsequent wettability contact angle distributions in both reservoir matrix and possible natural fractures. Also, the investigation will include validation of the grain/ pore-wall wettability regions and classify the natural wettability preference available inside pores of the rock and their overall wettability performance and recovery efficiency contributions. Further investigation will include modeling pore throat contact angle wettability, and to understand their new physics that will advance reservoir characterization and oil recovery improvement.
Geomechanical Modeling and Fractures Permeability Analysis to Identify Critically Stressed Natural Fractures and the Best Well Orientation for Optimum Production
Authors: Asadi Sadegh , White Adrian
Published: October 2023

Natural fractures influence fluid flow into or out of formations. This may take place under in situ conditions but is more likely under stimulated conditions. How fractures behave depends on the natural fracture properties and geomechanical state of the field. If the natural fractures can retain the enhanced permeability due to shear slip brought about by injection, then the pressure-stimulated natural fractures can contribute significantly to production enhancement. To assess the impacts of natural fractures in an intended operation, it is essential to characterise the natural fractures, relate their properties with the geomechanical conditions and model their responses to changing geomechanics during fluid injection (drilling, stimulation) or production.

This study aims to characterise natural fracture permeability under in situ stress conditions to determine the best well orientation in order to intersect the greatest number of critically stressed fractures and, ultimately, optimise productivity from future wells. Analytical modelling, considered the in situ conditions, is undertaken to calculate the downhole pressure required to initiate shear slip on well-oriented fractures, make them critically stressed and hence permeable to drilling fluid. Given knowledge of the stress state, the distribution of natural fractures, and the properties of those fractures, it was possible to select the best directions to drill a well to maximise productive contact with the reservoir.

Modelling showed that the interpreted fractures would require different pressures (from 10.8 to 16.7 pounds per gallon, ppg) to become critically stressed. Critically stressed fractures strike approximately parallel to the azimuth of the maximum horizontal stress (160°N) and dip ~60°. The interpreted fractures have a wide range of dips in different wells, ranging from horizontal to vertical whilst most of them are generally steeply-dipping. Fracture trends are predominantly NW-SE except in one well where they trend NE-SW. The best well trajectory to encounter the most permeable fractures is required to be highly deviated, 60° - 85°, and parallel to the azimuth of the minimum horizontal stress (070°N). Results showed some variations from well to well, with one well appearing to be an outlier due to the different fracture population interpreted from the image data. Wellbore trajectories were optimized to take advantage of critically stressed fractures for maximum production from the fractured reservoir.
Use of Logging While Drilling Data and Machine Learning to Predict Maximum Borehole Diameter for Multistage Completion
Authors: Khan Khaqan , Tammar Murtadha J. , Alfaraj Rima , Alidi Rayan
Published: October 2023

Stress-induced borehole wall failure during oil and gas wells drilling can lead to over-gauged wellbore. Borehole instability leading to excessively enlarged wellbore can not only increase risk of drilling difficulties but can also cause completions integrity issues. For instance, there is a high probability of poor cementing or compromised zonal isolation across over-gauged wellbore sections in cased and cemented completions or it can result in loss of packers sealing in open hole multi-stage (MSF) completions. Both of these inadequacies of poor cementing and insufficient packers sealing can jeopardize well stimulation operations. Hence, knowing accurate wellbore shape and diameter is critical for multistage well completion requirements.

While wireline multi-arm mechanical caliper tools can be run in open hole after drilling to get direct measurement of hole size, not always such measurements are possible due to prevailing drilling difficulties. Under such circumstances, making completion decisions become even more difficult with higher risk of failure. Moreover, a solo wireline logging run to acquire caliper data requires additional cost including rig time. The objective of this paper is to predict synthetic caliper using logging while drilling (LWD) measurements (notably azimuthal density and petrophysical properties) with the help of artificial intelligence (AI) and machine learning algorithms that can be used in place of wireline caliper data thereby saving rig and logging costs and hence reducing overall field development expenditure.

This paper describes a machine learning algorithm to predict the mechanical caliper logs using LWD data. Available LWD data for different wells were used to build a robust machine learning algorithm in Python. Different logging parameters from LWD were tested to quantify their sensitivity towards the caliper data and then predict the maximum hole diameter (Cmax) for different wells. The LWD data combines different parameters that have direct effect on the caliper log with machine learning model combining them for different wells to train the model and then predict caliper log based on these parameters. The parameters used in the prediction are gamma ray, four azimuthal photoelectric factors, sonic data, porosity, formation bulk density, four azimuthal formation densities, and mineralogy. The methodology is tested for horizonal wells drilled using 5-7/8" drill-bit. The predicted caliper is compared with measured caliper data so that it satisfies completion requirements for both MSF and cased hole completions.
Unleashing the Potential of Siliciclastic Reservoirs in the Sepinggan Carbonate Sequences, A Discovery in the South Mahakam Field, Lower Kutai Basin
Authors: Wuryanto Argo , Lauwijaya Wilsen Supriady , Yoga Thomas Yunanto , Trianto Andar , Kurniawan Firman Budi , Widiartha Rizzasila , Ramdan Dadan , Hartanto Sri , Sianturi Julfree Anto Dongan , Hidayat Rahmad , Moersidin Kelik Nugroho
Published: October 2023

The M-1x exploration well has successfully identified substantial hydrocarbon discoveries within the Sepinggan Deltaic Sequences (SDS) and Sepinggan Carbonate Sequences (SCS). However, investigating siliciclastic reservoirs in the shallow part of the SCS in the Mahakam PSC has been hindered by challenges associated with carbonate intervals. In this study, recent seismic reprocessing data is utilized to enhance structural predictions and reservoir characterizations, providing valuable insights for future well development.

A comprehensive suite of logging acquisitions, including pressure-fluid analysis and drill stem tests (DST), was implemented to validate the properties and extent of a mixed siliciclastic-carbonate reservoir system. Although carbonate reefs and platforms dominate the interval, this study primarily focuses on the siliciclastic layers, comprising stacked sandbars occasionally interspersed with channel formations across the shelf. Utilizing recent seismic data and attributes such as variance, impedance, and spectral decomposition, an improved understanding of horizon interpretations and fault properties, encompassing their geometry, throw, and extension, was achieved. This integrated approach, combining structural understanding, sedimentological context, and seismic attribute analysis, provides a comprehensive perspective on the distribution of siliciclastic reservoirs bounded by faults and carbonate reefs.

A detailed 3D grid geological model was constructed to visualize the reservoir distribution while considering fault geometry. This model facilitates the estimation of hydrocarbon in place and enables the identification of the influence of structural components on facies patterns and reservoir distributions. Uncertainty analysis was performed on parameters including alternative horizon interpretations, facies distribution, porosity, water saturation, and fluid contacts. Over 10 wells were meticulously selected for the development plan, utilizing a combination of static geological modeling and dynamic reservoir simulation, with the primary aim of optimizing the understanding of reservoir characteristics and achieving optimal well placement.

In conclusion, this study provides a comprehensive investigation into the hydrocarbon potential of mixed siliciclastic and carbonate environments in the South Mahakam area. The enhanced understanding of structural and sedimentological interpretations of reservoir characteristics and distribution will significantly contribute to uncertainty assessment during field development and the exploration of new areas for prospects, both within and beyond the current production field.
Decoding Contaminants. A Case study to Understand Source, Origin, and Distribution of H2S and CO2 off the Coast of Sarawak, Offshore Malaysia
Authors: Masoudi Rahim , Nayak Satyabrata , Patrick Panting Alexander Tarang , A Hamid Nuril Anwar Ahba , M Diah M Amri , Samsuri Muhammad Nazam , Hoesni Jamaal
Published: October 2023

In the shallow offshore region off the coast of Sarawak, Malaysia, exploration, development activities, and oil and gas production have been significantly affected by the presence of high concentrations of contaminants, mainly H2S and CO2. This has led to stranded hydrocarbon discoveries in the central Luconia area. The primary aim of this research was to uncover the origins of these contaminants and predict their distribution throughout the basin. To achieve this objective, an integrated regional petroleum system modeling approach was undertaken in the study area. The focus was on identifying the sources, origins, and distribution patterns of CO2 and H2S. By employing advanced modeling techniques and incorporating isotope analysis, this study provides valuable insights into the sources and distribution patterns of the contaminants. Based on the analysis of geochemical data and petroleum system modeling, it is suggested that the CO2 in the Sarawak basin may have originated from calcareous shale (Pre-Cycle I), coaly shale (Cycle I), and a magmatic source. Meanwhile, preliminary analysis indicates that the amount of H2S encountered in the study area could have been generated from various sources and processes. Overall, this research sheds light on the complex nature of these contaminants and lays the groundwork for a more comprehensive understanding of their origins and distribution patterns in the region.
Addressing Detrimental Effect of Water Emulsion to Pour Point Depressant Application While Managing Fit-For-Risk Wax Mitigation in Banyu Urip Field
Authors: Rois Muhammad Amin
Published: October 2023

High wax content characteristic of Banyu Urip (BU) crude is mitigated by continuous Pour Point Depressant (PPD) injection at multiphase stream. PPD treatment aim to lower Pour Point to 24°C with dosage of 475 ppm. It was observed that PPD dosage started to increase up to 650 ppm. This caused significant incremental cost as PPD accounts for 10% of total field OPEX. This paper shares rigorous troubleshooting method for resolving PPD performance degradation due to higher water cut.

To optimize the PPD dosage while ensuring that the wax or crude gelling risk can be well mitigated, following activities were undertaken: [1] Critical parameters data collection and root cause analysis; [2] Formulation of solution to address the root cause; [3] Trial at laboratory scale as the early proof of concept toward the proposed solution; [4] Risk assessment that includes thorough analysis of crude gelling in each pipe section and mitigation required; [5] Field testing and monitoring.

As the Banyu Urip field mature, the water cut increases more than double in a year. This condition creates water emulsion that has a detrimental effect on PPD effectiveness. Redistributing PPD injection from multiphase stream at well pad to dry crude stream at inlet export pipeline is deemed necessary to mitigate such issue. Detail review was conducted to assess the risk of reducing PPD dosage at well pad to processing facility especially during unplanned shutdown. Force balance equation was utilized to calculate minimum allowable gel strength in each pipe sections considering different pipe dimension, available pressure in the system, and temperature cool-down profile. Section which has the lowest minimum allowable gel strength and faster cool-down rate was used as governing case for PPD treatment strategy.

The lab testing using artificial water emulsion homogenizer also performed to verify PPD effectiveness at different injection stream. This also gives an indication of required dosage and required pump injection capacity for the proposed scenario. The PPD redistribution field testing was then carried out with successful result of 175 ppm (~27%) dosage reduction by leveraging existing facility with fit for purpose approach.

This paper provides insights how important the effect of water emulsion should be considered in the design phase, especially to stipulate PPD injection point location. This paper also provides guidance in determining PPD performance criteria using gel strength and pour point test with one-degree interval. Thus, operation strategy to mitigate crude gelling within a processing facility can be carefully developed.
Fracture Characterisation Methods and Application of Unconventional Oil and Gas Reservoirs in Reservoir Numerical Simulation
Authors: Li Qiaoyun , Wu Shuhong , Cao Zijian , Wang Baohua , Li Hua , Jia Han
Published: October 2023

It's necessary to solve the problem of fine characterization and efficient simulation of three types of fractures, i.e. natural fractures, artificial fractures and complex fracture network, for the development optimization design and scheme adjustment of unconventional oil and gas reservoirs. This paper describes a set of efficient and practical fracture characterization techniques for reservoir numerical model, which integrates various numerical simulation methods of fractures in different scales, including single-medium equivalent model, LGR model, double-medium model, MINC model, non-structural discrete fracture model and embedded discrete fracture model. For different reservoir types and different fracture dimensions, different models are adopted to depict the spatial distribution and fluid flow characteristics of fracture-matrix, matrix-matrix and fracture-fracture. The application in a shale gas shows that the set of fracture characterization methods can accurately describe the shape, geometric characteristics and spatial position of natural fractures, artificial fractures and fracture network. The methods also can simulate the fluid flow characteristics in multi-scale fracture network efficiently, and accurately predict the productivity of fracture network.
The forward cascade of sea ice floes in the Weddell Sea
Authors: Gupta Mukund , Regan Heather , Koo YoungHyun , Chua Sean , Li Xueke , Heil Petra
Published: October 2023

Sea ice is a material composed of polydisperse floes whose geometries evolve in response to conditions in the surrounding ocean and atmosphere. Due to sparse observations, quantifying the influences of basin-wide forcings on floe behavior has remained a challenge, and past studies have instead focused on finer-scale dynamics in driving the summer break up of the pack. Here, we combine high-resolution altimetry and imagery to characterize the life cycle of floes in the Weddell Sea, which we link to large-scale dynamics inferred from sea ice age estimates across the gyre. We demonstrate that basin-wide solar heating and oceanic circulation govern the floe size and thickness distributions during break up, in a forward cascade involving synoptic, mesoscale and floe-scale forcings fracturing ice into increasingly smaller pieces. This cascade is arrested by lateral erosive processes acting at the sub-floe scale, as evidenced by the three-dimensional rounding of floes during summer. We hypothesize that projected basin-scale changes over the next decades may accelerate the forward cascade of sea ice and result in smaller floes that are more vulnerable to melt.
Assessment on Effect of Thermal, Mechanical and Water Absorption Properties of Hybrid Hemp/Pine Apple/Palm Fiber Reinforced Epoxy Composite
Authors: Rallabandi Sivasankara Raju , Pilla Devi Prasad , Srinivas Lakshmi , PANDI Thimothy , VUDDAGIRI Hari Kiran
Published: October 2023

Natural fiber composites have been shown to be capable of replacing synthetic fiber composites in a variety of structural applications. However, natural fibers are hampered in their composite applications by their low dimensional stability and high susceptibility to moisture absorption over time. In this study, hemp, pine apple, and palm fiber were used to make natural hybrid fiber composites that were made with epoxy matrix. This study used variable fiber content to analyze the qualities of composites like thermal, mechanical, and water absorption. Thermal degradation of fiber polymerization was investigated via thermogravimetric analysis (TGA), revealing that the fibers such as hemp, pine apple and palm are stable up to 241°C, 166°C, 276°C. According to the findings, pine apple composites outperformed the other composites in terms of brittleness index and water resistance. When compared to pine apple composite, hybrid (palm + hemp + pine apple) composite exhibits greater tensile strength (14%), flexural strength (29%), and water absorption (34%). When exposed to water, however, the mechanical performance of all the composites dropped dramatically. The insulating capacity of hybrid palm and pine apple fiber composite is 8.22% greater than that of pine apple fiber composite. The Scanning electron microscopy (SEM) was used to analyze the fiber morphology and interfacial bonding in composite samples that had undergone tensile fracture.
Alterations in physio-biochemical parameters due to induced chronic heat stress in Sahiwal and Tharparkar cattle
Authors: Kant Lata , Kittur Priyanka M. , Patel Pankaj , Verma M. R. , Verma V. , Samad Hari Abdul , Chouhan Vikrant Singh , Singh Gyanendra , maurya Vijaiprakash
Published: October 2023

The intended objective of the present research was to investigate more about the "thermoadaptability of Tharparkar and Sahiwal cattle under induced chronic heat stress". Healthy male animals between the ages of 2.5 and 3 years were chosen for the study and split into two groups (five animals in each group). For the study five Sahiwal cattle and five Tharparkar cattle were selected which included a 7 day acclimatization period, 49 days of heat exposure at 38°C (6 hours each day) and a 7 day recovery period. Recording of Physiological responses like rectal temperature and respiration rate was done on daily basis. During the experimental period it was observed that in Sahiwal group, rectal temperature and respiration rate increased significantly (p < 0.05) in comparison to Tharparkar during heat stress period as compared to control period. The collection of blood was done weekly on -7, 0, 7, 14, 21, 28, 35, 42, 49, 56 days. During the period of heat exposure the level of serum ALT, AST, ALP significantly (p < 0.05) increased in both Tharparkar and Sahiwal breed as compared to control period. The level of serum ALT, AST, ALP was found to be significantly (p < 0.05) higher in Sahiwal group as compared to Tharparkar. During the heat exposure period TAC in both the breeds was significantly (p < 0.05) increased. The level of serum protein during the heat exposure period was significantly (p < 0.05) reduced in both the breeds although no significant (p > 0.05) difference was observed between the breeds. Our findings indicated that the plasma biochemical markers in both breeds are more negatively impacted by heat stress. Additionally, among the native breeds, Tharparkar cattle displayed the least amount of biochemical changes in response to heat exposure and can therefore be regarded as more thermo-adaptable than Sahiwal cattle.
SupportPrim – A computerized clinical decision support system for stratified care for patients with musculoskeletal pain complaints in general practice - Statistical Analysis Plan
Authors: Lervik Lars Christian Naterstad , Bach Kerstin , Granviken Fredrik , Hill Jonathan C. , Simpsom Melanie Rae , Vasseljen Ottar , Windt Danielle A. Van der , Meisingset Ingebrigt
Published: October 2023

This is a statistical Analysis Plan (SAP) for “SupportPrim – A computerized clinical decision support system for stratified care for patients with musculoskeletal pain complaints in general practice”. The SAP elaborates the statistics described in the published study protocol.
The structure of this SAP follows the guidelines provided by Gamble et al (Available at: https://jamanetwork.com/journals/jama/fullarticle/2666509) and the checklist available from: http://lctc.org.uk/SAP-Statement
All analyses will be reported according to CONSORT extension for Cluster Trials updated 2012 and ICH E9 guidelines on Statistical Principles in Clinical Trials