bluuebunny/crossref_metadata_2025 huggingface dataset:
Automating Reservoir Pressure Measurement Insights from Deep Water Carbonate Formations in Brazil
Authors: Bertolini A. , Dantas M. , Haik E.
Published: October 2024

The primary objective is to achieve consistent pressure measurement acquisition while optimizing the time required for high-quality data collection. Specifically, for carbonate formations in deep water Brazil, where reservoir intervals often exceed 200 meters, the aim is to streamline wireline formation tester programs, which can typically take less than a day up to a few days depending on formation thickness and type.

To achieve desired efficiency in pretesting acquisition, we implemented an automated workflow and AI classification of pretests. Automation reduces human intervention in tasks at the pretest station. The AI, a supervised algorithm trained on a generalist dataset of pressure build-ups, predicts valid or invalid pretests within the first 60 seconds. This enables rapid decision-making to either wait for pressure stabilization or abort and retry with different parameters. We measure total station time and time between events/pretests, comparing these metrics with other wells in the same reservoir to evaluate efficiency.

The proposed solution was successfully implemented in three carbonate formation fields in Brazil. The results, compared with previous manual pressure measurement sequences, demonstrated significant improvements. The total time required to complete the pressure campaigns was reduced, and the measurement sequence was optimized at all stations. A standardized protocol for pressure measurement was established, with consistent pressure stabilization criteria applied across the entire reservoir intervals.

Automation in WFT pressure measurements yielded positive outcomes. The WFT probe set and retract times were optimized at all pressure stations, and the build-up pressure behavior was evaluated within a 60-second window, enabling quick decision-making within minutes. These advancements highlight the efficiency and effectiveness of automated pressure measurement in deep water carbonate formations.

For over 50 years, WFT pressure measurements have been integral to formation evaluation programs, typically relying on experienced professionals for high-quality data acquisition. This paper introduces a novel automated solution that complements traditional methods, enhancing data quality and significantly reducing rig time, thereby advancing the current state of knowledge in the petroleum industry.
Technical Competence Management - ELNG TCM Program
Authors: Qabel A.
Published: October 2024

Objectives/Scope

In the context of building organizational capability, Technical Competence Management is an essential role in the dimension of "People" and an effective method to achieve operational excellence guaranteeing the achievement of company strategic and business objectives. Egyptian LNG adopted Technical Competency Management (TCM) framework for guaranteeing world class competency management system supporting in producing LNG safely, reliably, and efficiently and creating competency-based organization.

Methods, Procedures, Process

TCM framework was established to manage entire technical competences of technical workforce through:

Results, Observations, Conclusions

TCM swapped from ordinary talent development approach into management approach that focuses dynamically as a companywide upskilling program for serving company strategic and business objectives through:

TCM diverges between employees’ safety critical competence to be assured for the purpose of preventing major hazard accidents, and other required technical competences for performing positions functions. These aids company to declare feasibilities and define priorities of future talent development schemes.

TCM maintain all competence candidates’ records aligned with their positions’ Competence Profiles. This serves company to identify talented people for future succession/promotion plans, and to define properly the individual development of Not-Yet-competent people to rectify pre-identified technical gaps.
Geothermal Energy to Reduce CO2 Emissions from Oil and Gas Fields
Authors: Ahmed A. A. , Assadi M. , Batee M.
Published: October 2024

The need to make oil and gas extraction cleaner and greener is more important than ever. The industry is facing a big challenge: how to cut down on its carbon emissions. In places like the North Sea, where oil and gas are taken from under the sea, machines powered by gas are a big source of pollution, causing about three-quarters of the emissions. This paper explores the potential of using heat from the Earth (geothermal energy) from old, unused wells to make oil and gas extraction less harmful to the environment. This study also investigates a special way to use carbon dioxide (CO2) in its supercritical form – a state where it acts like both a liquid and a gas – to help with this process. The work is divided into two main parts. First, we use computer models to simulate how well we can get heat from these old wells and convert the thermal energy to electric power. Second, integration between geothermal and other heat sources to maximize the energy output. Results reveal that the achieved outlet temperature at surface from a closed-loop borehole heat exchanger (CBHE) is found to be 90°C to 130°C to when circulating scCO2 at flow rates between 1.25 kg/s to 5 kg/s, resulting in electric power of 105.7 kW from one well. However, integration of the CBHE with other heat sources (i.e. waste heat) would result in increased power output e.g. 323 kW when circulating 10 kg/s of scCO2 due to increased turbine inlet temperature to 200°C. But circulating scCO2 at high flow rate reduces thermosiphon effect and increases friction losses through CBHE, which requires significant pumping energy. Pumping power increases up to 70% of the produced energy in the case with 10 kg/s of scCO2. The optimum scCO2 flow rate through the CBHE was shown to be 7.5 kg/s. In simple terms, our study shows how tapping into Earth's natural heat can make oil and gas extraction more environmentally friendly. This research is a step towards cleaner energy practices and shows that even traditional industries like oil and gas can find new, greener ways to operate.
New Insights in Bapetco New Wells Delivery Process
Authors: El-Bagoury Mohamed
Published: October 2024

Badr El-Din Petroleum Company (Bapetco) is one of the major operators in Egypt. Bapetco is one of the pioneer companies to apply the well delivery process. We have had a lot of advances to the well delivery process from best practices and the culture of process management in the last 40 years.

The well delivery process (WDP) was deployed in Bapetco to improve integration and communication between the different disciplines and to keep an effective time frame for new wells and subsurface projects. This process is compatible with the high-level business guidelines (assess, select, define, execute, and operate). These five elements facilitate the new wells workstream. Since 2015 a lot of revisions and continuous improvements have taken place to modernize the well-delivery workstream and replace the existing practice with agile reforms.

Installing the new wells process mainly depends on six factors; wells-to-facility integration, digital control and transformation, dual leading responsibility, document standardization, proactive tracking, and management of change (MoC). These tools and techniques were adjusted to accommodate the requirements of the national operating environment in a fit-for-purpose style. The deployed process describes the best practices in timely managed well proposals to ensure full alignment between internal and external stockholders and provide the required support to wells planning in creating robust execution plans.

This paper will demonstrate a description of the new wells delivery workstream and its key pillars in addition to the applied improvements that led to effective lean management, enhanced quality of work deliverables, and minimized time to first production including lessons learned during the pandemic COVID-19 world crisis.
Analysis and Modeling of an Extensive Data Material for the Compositional Variation with Depth in a North Sea Reservoir
Authors: Pedersen K. S. , Hjermstad H. P.
Published: October 2024

Detailed compositional data is presented for 43 fluid samples taken at different depths in a 359 m North Sea reservoir fluid column with a gas cap on top and an underlying oil zone. The data enables the depth of the gas-oil contact to be determined quite accurately. A common equation of state model has been developed for the fluids and depth gradient simulations carried out. In the gas zone, gravitational forces can explain most of the observed compositional variation. In the oil zone, the compositional variation is larger than can be explained by the gravitational effect. There is a need to also account for the heavy hydrocarbons orienting themselves towards the warmer bottom zone and lighter hydrocarbons towards the colder top zone. The Haase model, which is based on the theory of irreversible thermodynamics, is used to describe how the vertical temperature gradient affects the compositional gradient. It requires knowledge of the absolute partial molar enthalpies of the individual components, of which it thanks to the extensive data material has been possible to give a good estimate. With the presented model concept, it is possible to represent the compositional gradient over the entire fluid column including the depth of the gas-oil-contact and the variations in gas/oil ratio and saturation point with depth. The determined model parameters are also expected to be applicable to other petroleum reservoirs.
The Strength of Surface Seismic Attributes as a Quick Tool for the Dolomitization Detection in Alamein Carbonate Reservoir, Khepri Field, Shushan Basin, North Western Desert, Egypt
Authors: Raslan Y. , Deghaidy N. , Abdo K. , Morsi M. , Metwally R.
Published: October 2024

Khepri deep Field was discovered in 2020 by drilling the exploratory well KPR-D-1 which encountered 59 feet net pay in the Alamein dolomite reservoir and tested 4000 BOPD. The Alamein formation is recognized as a very good carbonate reservoir in this field with up to 4 million barrels of oil were produced there. Core analyses revealed that the reservoir attains up 15% vuggy porosity with about 20% residual oil saturation. Initial volumetric calculations were 7 MMSTB of original oil in place that increased to 10 MMSTB, where the Alamein structure elevated by about 50 feet. In order to understand any lateral changes related to subsurface geology, surface attributes have numerous applications in both structural and stratigraphic aspects. These applications depend on the extraction of data or information regarding amplitude, frequency, and phase from seismic data across a selected surface that represented the reservoir or between two surfaces. The main risk in this case is the dolomitization process; when dolomite is found in our wells at an appropriate structural level, oil is found as well. The density of limestone is higher than that of dolomite. Due to the fact that the secondary porosity produced by the dolomitization process lowers density, which in turn lowers seismic wave velocity. The important thing to remember is that dolomite, unlike limestone, is supposed to have a lower amplitude value and acoustic impedance. Our reservoir's seismic interpretation has been completed, and additional top and base surfaces have been made so that it can apply a variety of seismic properties through this zone in order to capture any events. Anomalies can be seen in some places and surrounding the main fault according to the minimum amplitude, average strength, sweetness, and RMS qualities. Thankfully, our data for lithological interpretation of dolomite from wells matches these abnormalities.
Simulating Lost Circulation in a Primary Cement Job Design
Authors: Bogaerts M. , Flamant N. , Abdulaal A. , Zalata R.
Published: October 2024

Losses can occur during many stages of well construction and with various severities, ranging from seepage losses to total losses. In an ideal situation, losses should be addressed and cured prior to the primary cementing operations, as losses can affect the cement job results in various ways. Losses during cement placement will affect top of cement (TOC), downhole equivalent circulating densities (ECDs) and potentially well control, circulating temperature, annular velocity, and mud removal.

In the Middle East, losses are common during drilling operations and often are present at the start of the cementing operations. If it is expected that a primary cement job will be executed with losses, it brings benefits to be able to simulate the results. This enables us to set realistic expectations toward the outcome of the cement job and enables educated decision making.

However, there are also cement jobs where losses are not expected but occur during the actual cement job. Having the ability to run simulations using actual execution data will enable the drilling team to make more educated decisions on the next steps of operations.

A proprietary cement job simulation software has been upgraded with a losses model. Using the losses model will enable the design engineer to define one or multiple loss zones in the wellbore. For each identified loss zone, a percentage of losses can be provided. The simulator uses the losses input data and other well and fluid data for a detailed dynamic simulation. The simulator will provide output for temperature, u-tubing, ECD, and expected TOC. Sensitivity simulations can be run toward the selected loss zone intervals and expected losses.

In case losses occurred when not expected or were more significant than anticipated, simulations can be run post-execution to visualize the outcome of the cement job. Using actual execution data and loss rate, the simulation results can be used to make a decision on the next operations. It will provide an additional input to decide to continue operations or if wireline evaluation logs need to be run ahead of possible remedial cementing operations.

In this manuscript, case studies will be provided where the loss circulation model was used during the design phase as well as during the job evaluation phase. The case studies will show how the model can accurately provide TOC and ECDs.

Using the novel loss zone simulations during cement job simulations enable the design team to discuss the potential outcomes of the cementing operations while experiencing losses. It will enable the team to prepare proper mitigation plans ahead of the cement job or to facilitate quick post-cementing decisions for upcoming operations.
Challenging Plug & Abandon Cementing Operation under Influx and Losses Scenario
Authors: Mesaud R. , Shafqat A. , Al-Jadhar A. , Kharchi S. , Bermudez F. , Pohl J.
Published: October 2024

The cement plugs are usually required when the well requires a sidetrack due to various circumstances such as a change in its trajectory, abandonment, or to cure loss circulation. These can occur in the initial drilling phase, just after drilling, or during the production phase. Requirements to perform these operations vary and may include different scenarios such as an increase of contact area with producing formation, producing formation depletion, production of unwanted fluids, non-economical hydrocarbons production, temporary isolation, regulatory, or operational issues including fish in the hole, casing repairs, formation squeeze, or to cure loss circulation.

Cementing plug operations are one of the most critical operations to be designed and executed, due to the required slurry and set cement properties, a relatively small volume of cement slurry that can be subject to contamination, critical design considerations, and meticulously required field execution. This manuscript presents the challenges and the engineered solution while designing, executing, and evaluating the success of a critical plug and abandon (P&A) cementing operation under an influx and losses scenario. This study will cover a challenging well that was not possible to be hydrostatic balanced without inducing fluid losses to the formation and the decision that was made to plug and abandon the well by pumping cement plugs.
Reconstructing Missing and Non-Recorded Well Log Data Using Machine Learning Techniques.
Authors: Amadi K. W. , Elgaddafi R. M , AlAli M. A , Dashti A. M
Published: October 2024

Petrophysical estimation of rocks are carried out for lithologic characterization and to quantify the reservoir hydrocarbon prospects. During drilling operation, the continuous recording of well log data is performed using Logging Whilst Drilling (LWD) tools and sometimes the LWD tool failure results in loss of data especially when decision was made to drill ahead due to project economics resulting in gaps or unrecorded data. This study is aimed at using Machine Learning (ML) techniques in predicting missing and unrecorded data using offsets well data. During the study detailed literature review addressing current industry trends in the handling gaps in petrophysical log were reviewed, then four ML models were trained and used in predicting lost data entries using offsets well log data. The models utilized comprised CatBoost (CB), Gradient boost (GB), Random Forest (RF) and Support Vector Machine (SVR). The ML algorithms were first trained with 21595 data points using a 70:30 percentage ratio for training and testing respectively. After that, 8650 data points from a different well were used to validate the developed model. The real-time drilling parameters required as input data includes Gamma ray(GR), neutron (NPHI), bulk density (RHOB), photoelectric absorption factor (PEF), the borehole diameter, (CALI). The modeling result showed a good match between the actual and predicted (logs) with coefficients of determination for training and testing dataset of 0.99 and 0.97 for CatBoost and RF respectively which are the two best predictors. The main added value of this approach is that the input drilling parameters are readily available in real-time and can timely aid in well placement decisions which improves the productivity of the well.
Developing of Lower Cretaceous Clastic Reservior for Menes-Nu Fields as Stratigraphic Play Using Integration of Multiple Data, North Western Desert, Egypt
Authors: Adly O. , Tarasov S. , Hassan M. , Sharaawy H.
Published: October 2024

Menes and Nu fields are discovered by Khalda petroleum company in 2016, the two fields located North west from Shushan basin. They are on a ridge high west from Umbarka field and North from fault bonding Shushan basin, also North from Barakat deep field, Distance between Menes -1x and UMB-1X almost 15 km to east, Nu are up dip from Menes and west from Menes closure.

The phanerozoic history of the Western Desert was shaped by opening of first Paleotethys and then Neotethys which morphed into the modern Mediterranean Sea when the seaway between Arabia and Eurasia closed about 15 Ma. Extensional structures related to Paleotethys are present in the subsurface of the Western Desert but are presently not well known. Neotethyan rifting, however, left a complex legacy of multi- phase basins along the northern margin of Gondwana (Bosworth and Tari, 2021).

Shushan basin lies to the south of Matrouh basin and shows the effect of ENE-WSW and WNW-ESE oriented faults on the basin architecture. Shushan basin witnessed Jurassic and early Cretaceous extension followed by late Cretaceous - Early Tertiary inversion (El Awdan et al., 2002). NE-SW and NNE-SSW oriented inversion anticlines as well as tilted fault blocks bounded WNW-ESE and NW-SE oriented normal faults from the main structural traps in the basins (Mostafta, 2008)

Menes and Nu are Cretaceous play where are the main reservoirs mainly in AEB and Alamein with rare pay calculated in Baharyia

The tectonic effect the area of deposition though to be there are uplift for the Paleozoic and Jurassic section before Cretaceous age where there are no Jurassic deposited and Paleozoic or eroded represented by Shia formation deposited directly on basement, unconformity represent the non-deposition age from Paleozoic to early Cretaceous
Advancing Rotating Machinery Condition Monitoring: Wireless Vibration Sensors in ADNOC's AIP5 Autonomous Operation Plan
Authors: Youssef K. , Alkaabi A.
Published: October 2024

Condition monitoring of rotating machinery is a critical aspect of maintaining operational efficiency, reliability, and sustainability in industrial sectors, particularly within the oil and gas industry. In an era where digital transformation is reshaping industries, ADNOC has embarked on a strategic initiative under its AIP5 autonomous operation plan to leverage advanced technologies such as wireless vibration sensors. This initiative aims to integrate cutting-edge wireless vibration sensors to enhance machinery monitoring processes, especially in remote and offshore environments.

The use of wireless vibration sensors in ADNOC's operations represents a significant step forward in digital transformation, aligning with the company's broader goals of innovation, sustainability, and operational excellence. This manuscript discusses a pilot project conducted within ADNOC Offshore to evaluate various sensor manufacturers, highlighting the benefits of wireless vibration sensors in reducing dependency on contractor mobilization, predicting machinery failures early, and improving overall operational efficiency.

In addition, this study details a workshop arranged with multiple Original Equipment Manufacturers (OEMs) to explore available products before initiating a pilot installation at one of ADNOC's offshore fields. A thorough comparison of seven OEM products was conducted based on their technical specifications, hazardous area classification, and customer references. This paper also examines the challenges faced during the COVID-19 pandemic, which underscored the necessity for wireless solutions to ensure continuous data acquisition and analysis without on-site mobilization.
Development and Optimization of Epoxy-Resin Based Cement Reinforced with Low-Cost Fly Ash for High Durability Environmentally Friendly Cement
Authors: Salib Ann Maria , Fakher Sherif
Published: October 2024

This research investigates the development of a novel, high-performance cement composite to address the limitations of traditional cement, including its environmental impact and durability issues. The study focuses on the incorporation of epoxy resin and fly ash to enhance the mechanical properties, durability, and sustainability of cement-based materials. A comprehensive experimental program was conducted to evaluate the effects of varying epoxy resin and fly ash dosages on the composite's properties. Results indicate that the incorporation of epoxy resin and fly ash significantly improves the composite's performance, including enhanced mechanical strength, increased resistance to acid and alkaline environments, and improved durability. The findings demonstrate the potential of this novel cement composite to offer a sustainable and high-performance alternative to traditional cement for construction applications
Successful Application of Innovative Well Intervention Technologies to Effectively Stimulate Extended Reach Wells
Authors: Alsubaie F. A. , Afif O. T. , Duthie L. S. , Harthi M. A.
Published: October 2024

Well interventions with coiled tubing (CT) have played a vital part in increasing well productivity. CT intervention challenges in 2.25" highly restricted extended reach wells demand technological solutions, excellent planning and in-place tailored procedures.

Fluid placement and effectively maximizing reservoir contact are critically important elements during CT interventions for open-hole matrix acid stimulations. Fluid delivery was accomplished with multiple extended-reach techniques, including concentration of friction reducer and volumes, contributing to extending the reach. Technologies such as CT tractors and agitators to increase the reach were selected after considering their performance in the wells. A specially tapered CT string was also employed in the field. Effective fluid placement was achieved through distributed temperature sensing (DTS) providing a real-time optimized pumping schedule.

The CT simulator predicted the CT lockup depth to within 5% of actual depth reached for the CT interventions. This allowed for proper selection of downhole tools and planning of fluid volumes to operate the hydraulic downhole tools. One of the most effective practices was cleaning the wellbore casing shoe with a high-pressure jetting tool (HPJT) to clean any organic or drilling materials, leading to a reduced friction coefficient. This HPJT run increased the reach by an average of 23%, and also reduced the operation time during the stimulation by 15%. Real-time tension-compression information from the bottom-hole assembly assisted in estimating the lockup depth and provided confirmation of the extended reach tool activation. The ERW's open-hole coverage was maximized, delivering an increased well productivity on every intervention.

These engineered solutions illustrate the potential for CT interventions in extended-reach horizontal wells to move the dial and contribute to well productivity. Continual innovation and introduction of new technologies not only play a key role in meeting objectives, they are essential for constantly pushing the boundaries in these ultra-challenging well conditions.
Automated Steering Tendency Estimation for Steering Ellipse Derivation
Authors: BA Samba , Omr Medhat , Mansour Darine , Sahli Hussein , Goel Prateek
Published: October 2024

With directional drilling being a major activity during well construction, using the industry 4.0 platform (Vaidya Saurabh 2018) to transform the operational aspect of well construction represents great risk and reward scenarios for proper planning and execution. In effect, the directional drilling process has grown in efficiency and complexity with a move to more and more 3D horizontal wells. This means that delivering consistent and efficient steering performance can be very tricky.

In this paper, the emphasis is put on an automated steering tendency estimation which is paramount for deriving efficient steering commands to meet trajectory targets without compromising on hole quality goals. In particular, we show a steering ellipse derivation for all rotary steerable system (RSS) downhole steering modes in real time (RT) and how it is used to understand the performance of the downhole controllers and adjust steering parameters accordingly automatically.

After examining what steering ellipse tendency estimation is and giving examples of steering tendency ellipse for different steering modes, a field application of this is discussed and it shows significant improvement in wellbore quality with lower tortuosity index.
Enhancing Oil and Gas Field HSE Training Through Virtual Reality
Authors: Adel A. , Elnogomi A.
Published: October 2024

The oil and gas industry, integral to the global economy, is inherently fraught with risks and hazards that pose significant threats to worker safety and operational efficiency. Given the high-stakes nature of this sector, rigorous Health, Safety, and Environmental (HSE) training is paramount. Traditional training methods—typically consisting of classroom lectures, instructional videos, and on-site demonstrations—while essential, often fall short in delivering comprehensive, immersive experiences that mirror real-world scenarios. Virtual Reality (VR) technology represents a transformative leap forward in enhancing HSE training, offering unprecedented levels of immersion, realism, and safety.

This manuscript explores the profound impact of VR on HSE training within the oil and gas industry. It provides an in-depth analysis of the technology's benefits, practical applications, and successful case studies. Moreover, it examines the complementary roles of Augmented Reality (AR) and Mixed Reality (MR) technologies, highlighting their potential to further elevate training outcomes.
Improve Imaging of Pre-Messinian Targets Through FWI and RTM in the East Mediterranean Region, Case Study
Authors: Darwish Tamer , Kumar Jyoti , Bell Marcus
Published: October 2024

The Eastern Mediterranean region has substantial hydrocarbon potential, marked by proven Jurassic/Cretaceous oil and gas reserves, Pliocene Nile-sourced sandstones, and the potential for Pre-Messinian carbonate buildups analogues to the Zohr discovery. Even though, the thickness of the post-Messinian section is generally limited in the Eastern Mediterranean region but the presence of the Messinian heterogenous evaporites introduce significant velocity contrasts in the overburden, which needs to be addressed to improve the image of the Pre-Messinian targets.

Accurate imaging of the Pre-Messinian targets faces several challenges, including correctly illuminating the sub-salt section and understanding of the interaction between clastic sediments and Messinian evaporites. This involves capturing the necessary velocity details of the heterogeneity within the Messinian evaporites and addressing illumination issues arising from the complex relief of the Messinian layer, including optimizing acquisition parameters (Kumar et al., 2022).

Optimizing the depth velocity model building process necessitates the application of advanced imaging technologies such as Full Waveform Inversion (FWI) and Reverse Time Migration (RTM) (Brandsberg-Dahl et al., 2017).

This paper proposes solutions for diverse overburden challenges to enhance the Pre-Messinian image. The results from this work demonstrate that the suggested VMB workflows including the application of FWI and RTM have been successful in capturing the majority of Post-Messinian and Messinian complexities, thereby improving the image of the Pre-Messinian target.

We present data examples from recent seismic surveys in the Eastern Mediterranean to demonstrate these novel solutions. Along with improved subsurface imaging, these recent seismic data could provide the interpreters with necessary input for a better understanding of potential high-quality reservoir facies.
Digital Twin: New Back Allocation Algorithm Based on the Maximum Likelihood Principle
Authors: Ishmuratov R. , Maslennikov D. , Guzhikov P.
Published: October 2024

The rapid advancement of digital technologies in the oil and gas sector has led to the development of innovative solutions for optimizing production and enhancing asset management. One such solution is the Digital Twin, a dynamic, real-time digital representation of physical assets. This paper introduces a novel back allocation algorithm for gas and gas condensate fields based on the Maximum Likelihood Estimation (MLE) principle, integrated within the Digital Twin framework.

The core thesis of this paper is the application of the MLE principle to the back allocation of fluids to wells and reservoirs, solving this task with the highest possible likelihood. The MLE-based approach allows for precise determination of fluid origins, pinpointing the specific wells and even the intervals within those wells, including the detailed component content.

For the MLE algorithm to function correctly, robust fluid characterization is essential. This involves comprehensive compositional grading and the use of Equations of State (EOS) to model fluid properties accurately. Understanding the compositional distribution from the output to the input, along with knowledge of how composition changes with depth and phase behavior at every node in the system, is crucial for achieving accurate back allocation using MLE.

Key aspects of the Digital Twin and MLE-based back allocation algorithm include:

Accurate Fluid Allocation: Determining the most probable production rates and fluid origins by adjusting parameters such as flow rates, fluid compositions, and equipment dimensions to minimize deviations. Compositional Grading: Utilizing detailed compositional data to understand how fluid properties change with depth, which is vital for accurate modeling and allocation. Equation of State (EOS) Models: Employing EOS models to accurately describe fluid phase behavior under various conditions, providing the necessary data for the MLE algorithm to function effectively.

This integration of MLE within the Digital Twin environment enhances the accuracy of production allocation, leading to significant improvements in operational efficiency and economic performance. Case studies from gas and gas condensate fields demonstrate the algorithm's capability to optimize production allocation, reduce operational risks, and enhance overall asset management.

This paper will detail the technical aspects of the MLE-based algorithm, the importance of fluid characterization and EOS models, and the resulting benefits in terms of production optimization and economic gains. The findings suggest that adopting this advanced back allocation approach can lead to substantial improvements in field development strategies and operational efficiency.
No Risk, No Reward: A New Era of Risk-Based Hydrate Management for Gas-condensate Developments
Authors: Sherrard C. J. , Poursanidis K. , Georgis M. , Golczynski T. , Hamilton S.
Published: October 2024

The integration of digital solutions, engineering expertise, operational knowledge, and advanced laboratory testing is unlocking value in stranded assets. By assessing the unique fluid properties and operating conditions of each asset, cutting-edge technologies, laboratory analyses, and modeling techniques can be leveraged to quantify hydrate formation and plugging risks in economically marginal gas- condensate fields. Hydrate management strategies have facilitated the development of numerous projects worldwide that were previously considered unviable due to economic and technical challenges. While there is extensive literature on risk-based hydrate management approaches for oil systems, this paper focuses on the emerging application of these strategies in gas-condensate developments.

Collaborations with leading flow assurance laboratories and academic institutions enable quantification of hydrate risks associated with a project. By analyzing the critical factors for stable hydrate formation, these developments gain an additional layer of confidence, enhancing their attractiveness for investment. Utilizing the latest hydrate kinetics software embedded in OLGA (e.g., UWA, CSMHyk) provides a more pragmatic approach to subsea design for hydrate management. The insights and methodologies shared in this paper demonstrate leadership in flow assurance, guiding the implementation of effective solutions and driving future growth and optimization of production processes.

Furthermore, this paper emphasizes the importance of a robust hydrate remediation strategy to minimize production deferment due to hydrate blockages. It highlights the need for upfront investment in critical infrastructure to ensure the swift and efficient resolution of any blockages that may occur throughout the field's life.
Enhanced Machine Learning Modelling Techniques for Better Classification of Carbonate Reservoir Rocks
Authors: Hamada G. , Al-Khudafi A. M. , Al-Yazidi A. T. , Al-Sharifi H. A. , Al-Qadhi T. , Al-Gathe A. A.
Published: October 2024

This study aims to enhance machine learning models for classifying carbonate rocks into limestone and dolomite using well logging and core analysis data. The research evaluates various machine learning algorithms' performance and identifies effective techniques to improve model accuracy for geological and environmental applications.

The study employed several strategies to improve classification models, including grid search, random search, Bayesian optimization, SMOTE, and ensemble techniques (boosting and bagging). A dataset of 4290 points was used to train eight different classification models: Random Forest (RF), Multilayer Perceptron (MLP), Naive Bayes (NB), K-Nearest Neighbors (KNN), Support Vector Machine (SVM), Radial Basis Function (RBF), Regression Tree (RT), and Parallel Additive Regression Tree (PART).

All implemented strategies significantly enhanced the machine learning classification models, achieving a correlation coefficient near one and a mean absolute error of 0.16 averaged across all techniques. Random Forest and Multilayer Perceptron demonstrated exceptional performance, with accuracy rates of 99.2% and 98.7%, respectively. The Kappa statistic further confirmed the superiority of these models. The study highlights the importance of selecting appropriate machine learning models and optimizing their hyperparameters for effective carbonate rock type classification. The findings underscore the potential for improved accuracy through ensemble methods and hyperparameter optimization in geological classification tasks.

This research provides new insights into applying machine learning techniques for geological classification, particularly in carbonate rock type identification. The results have significant implications for developing more accurate and reliable classification models in geoscience applications, potentially improving various geological and environmental studies.
Monitoring the Liquid Level of Shale Oil Well Through EM Telemetry, a Case Study
Authors: Chen Qiang , Jia De-li , Sun Fu-chao , Hao Zhong-xian
Published: October 2024

Shale oil had been invested heavily in China, as exampled by Daqing oil field, Xinjiang oilfield and so on. The liquid level of shale oil well was generally tested through acoustic means at the wellhead. This method was not accurate due to factors such as the wax, dead oil and well deviation, incorrect data led to the wrong development strategy or even downhole pump damage.

In this paper, downhole telemetry was raised based on EM transmission, its working principle was discussed. Relevant tools were manufactured based the principle, field trial was also completed in the oilfield.

EM had been familiar to us for the purpose of communication, but its application downhole was a complete different scenario due complex electric conductivity environment. We explored the downhole EM transmission mechanism and developed the tubing-casing-subsurface channel model, low frequency EM source at the tubing could pass through casing to enter the reservoir and be detected on the ground. To turn the theory into reality, we designed the telemetry system including the modules of electric circuit, coil, metal centralizer and receiving device. Electric circuit could modulate the pressure data into low frequency alternative current and pass it to the coil module. Under the effect of alternative current, the coil module would induce magnetic field on the tubing with the pressure date. EM signal could flow along the path of metal centralizer and penetrate the casing to enter the subsurface, the receiving device could detected the voltage potential between wellhead and ground, its precision was microvolt level. Downhole liquid pressure monitoring gauge was manufactured and tripped into shale oil well up to 1466m to gain the knowledge of liquid level. The signal attenuated as the gauge went deeper but was still 1.5 times of noise at the bottom of well. The gauge helped the operator monitor the change of liquid level and took relevant measures accordingly if the change was abrupt.

This paper prescribed the application of EM into downhole liquid level monitoring. We shared the experience with our counterparts and helped the expansion of downhole telemetry technology.
Delivering Wells Without Backreaming: Implementation of High-Performance Water Base Fluid System with Highly Inhibitive Triple Mechanism in Unconventional Wells in The UAE
Authors: Al Menhali Shamsa , Anez Marcos , Marzouk Ahmed Mortadi , Khatib Faiz
Published: October 2024

A customized high-performance water-base fluid system was used to drill intermediate sections in an unconventional gas field located in Abu Dhabi, UAE. The customized system with a highly inhibitive triple-mechanism was used to drill troublesome shale formations achieving high rates of penetration without any bit-balling or shale related incidents. One challenge commonly faced while drilling these formation is the excessive back reaming required while tripping out of the hole. However, the superior performance of the fluid system ensured that tripping out of the hole was achieved by using only elevators, without any backreaming, saving a significant amount of rig hours. This paper discusses the design, implementation and results obtained by implementing customized high-performance water base systems to drill troublesome shale formations in six wells in the unconventional gas field.
Improved Regional Geological Understanding And Impact On The Hydrocarbon Prospectivity Of The West Mediterranean, Egypt
Authors: Hamilton M. , Gewaily A. H. , Khattab M. , Hussein M. , Mahran N. , Basher K. , El Mahdy M. , Elokazy M.
Published: October 2024

Egypt's west Mediterranean is a truly frontier basin in terms of hydrocarbon exploration, however, continued seismic data acquisition and exploration drilling scheduled for 2024/2025, is driving the region towards becoming an exploration hotspot. Regional 2D seismic data and a 24,000 sq km merged 3D seismic volume have recently been supplemented with two additional broadband 3D seismic volumes. Along with improved imaging, these recent seismic data allow interpreters to focus on stratigraphic elements and have more confidence in structural interpretation compared with 2D limitations.

The larger of the new multiclient 3D seismic surveys is located on the northwest of the offshore Nile Delta cone and west of the Rosetta fault trend, connecting the west to the more mature Nile Delta understanding and also having a direct tie to the Kiwi 1 well. The subsurface imaging is challenging, with complexities such as both dirty and clean evaporites as well as shale intrusions and extrusions being present. These challenges have been addressed using high-end depth imaging workflows. In the final 3D seismic volume, it is possible to extract spectacular channel systems in both Post and Pre-Messinian evaporite sections, using various seismic attributes, providing the interpreters with a better understanding of where high-quality reservoir facies may be located. Primary targets in this area are likely to be Oligo-Miocene clastic reservoirs in combination stratigraphic-structural traps, with secondary targets in the Pliocene shallow section.

In contrast, the second new multiclient 3D seismic survey is located far to the west and almost entirely on the shelf. These surveys are however linked by a large 3D merge volume, which allows the explorationists to have an excellent regional geological context. The new survey is extremely close to the Sidi Barrani 1 well, which was drilled on 2D data, and is thought to have failed due to poor trap definition. This is something the new 3D KPSDM depth seismic volume addresses, allowing explorers to better image and define traps in the area. Targets in this survey are most likely to be Jurassic and Cretaceous clastic reservoirs in structural traps.

Improved regional understanding has been achieved using these seismic data and this work highlights some of the imaging complexities and prospectivity using relevant seismic examples.
Effect of Knowledge of Bubble Point Pressure on Estimating PVT Properties from Correlations
Authors: El-Banbi Ahmed H. , El-Maraghi Ahmed
Published: October 2024

PVT properties are needed as input data in all reservoir, production, and surface facilities engineering calculations. In absence of PVT reports on valid reservoir fluid samples, engineers rely on PVT correlations to generate the required PVT data. Accuracy of PVT correlations vary and no correlation group has been found to provide accurate results for all oil types. The effect of inaccurate PVT data can be significant in engineering calculations and is well documented in the literature. Bubble point pressure can be sometimes obtained from external sources. In this paper, we show how to utilize the known bubble point pressure to improve the accuracy of calculated PVT properties from correlations.

A systematic study using around 250 reservoir oil samples was conducted to quantify the effect of pre-knowledge of bubble point pressure. The samples spanned a wide range of oils from very volatile oils to black oils and all the way to low-GOR oils. A method for shifting both undersaturated and saturated sections of the PVT properties curves to the correct bubble point is explained. Seven PVT correlation families were used in this study. All PVT properties (e.g. solution gas-oil ratio, formation volume factor, density, viscosity, and compressibility) were calculated using the correct bubble point pressure and the correlation estimated bubble point pressure. Comparisons between the calculated PVT properties, and actual laboratory measured values were made. It was found that pre-knowledge of bubble point pressure and using the shifting technique presented in the paper, improved the correlation-estimated values up to more than 30%. The most improvement was seen in solution gas-oil ratio and oil formation volume factor.

A technique to improve the accuracy of PVT properties derived from correlations was introduced. It improves the accuracy of all derived PVT properties for oil with variable degrees.
Driving Operational Excellence in Oil Gas Sector ETHYDCO Innovative Pi System Integration
Authors: AFIFI M. T.
Published: October 2024

The Petro-chemicals industry is a special industry. All transactions and data processes must be comprehensively managed. Such includes reliable equipment, if it is a failure not only cost money (maintenance man hours or Spare parts inventory) but also the maintenance downtime of the job rates directly impacts production and reflects on company sales. Saving energy: Sources from operation systems that generate energy (E.g., Steam, fuel gas, heat transfer) decrease the amount wasted as long as they are cycled back together (or treated). Thus, energy utilization can be decreased in all respects. Human safety and compliance A data management system that is not a real-time insight platform or intelligent All this inevitably leads to a potential increase in the operator's operational costs (maintenance, etc.).

A leader in the Egyptian petrochemical industry, ETHYDCO is committed to achieving operational excellence and thus retaining its competitive edge in this field. Its strategies include raising the level of productivity, saving some energy costs, decreasing overall operating costs, and adopting cutting-edge technologies which led to efficiency gains over time as well as promoting sustainable development.

To address these issues, ETHYDCO has adopted the PI System, an industry-proven performance monitoring system. The strengths of the PI System are in wide data collection and acquisition possibilities, real-time storage of data from different sources and constant data analysis that may help to monitor operations, detect the signs of wear out facilities and equipment, and thus may help in decision making process.