bluuebunny/crossref_metadata_2025 huggingface dataset:
Challenges of Full Field Polymer-Flood Development from Front End Management of Large Dark Brown Field Towards Delivering Competitive Commercial Scale Project Paper Number: SPE-222812-MS
Authors: Rawahi Z. , Riyami O. , Hadhrami W. , Habhouba E. H. , Qayum S. , Khaziri S. , Huisman S. E. , Nasralla R. , Harthy S. , Zadjali R. , Brown M. , Farsi S. , Nadeem M. , Jadeedi H. , Sulaimani H. , Nofli S. , Hinai S.
Published: November 2024

Polymer flood is a mature technology where it has been applied in several fields in the past decade in Petroleum Development Oman (PDO) whether in full field scale or pilot/trial scale and at different development concepts (vertical and horizontal polymer injection concepts). However, managing such opportunities to develop them at commercial scale competitively is still deemed to be a challenge especially in a dark brown field from Urban Plan, interface/stakeholders/risk management, contracting strategy and execution prospectives. For the field of subject in this paper, full field polymer development plan and concept selection was endorsed with the concept of developing the polymer project utilizing the existing wells stock drilled during the infill waterflooding phase. Polymer flood is scheduled to be on-stream in 2026 injecting polymer in 2 phases with over 100 polymer injectors in total.

The field is a mature dark brown field in South of Oman with waterflood history of over 16 years. Due to the congested nature of the field, it was difficult to define a cost-effective polymer development concept for the entire field. More challenges were faced managing several complexities i.e technology maturation, resources constraint & continuity, contracting strategy endorsement and managing different stakeholders integrating all interface aspects. However, with continuous persistence and innovation, the project has managed to mature total volume of ~ 6% increment with remarkable unit cost reduction (> 50%). Furthermore, additional opportunities were identified to reduce the Unit Technical Cost (UTC) further by 4–5 units cost toward execute phase mainly more efficient polymer facility and chemical costs through competitive contracting strategy and introduction of Category management (CM) approach with further scope optimizations. In terms of Green House Gases (GHG) reduction, the project has demonstrated CO2 reduction in the field to more than 50% compared to Field Infill Waterflood development. This is due to the polymer nature of reducing the water cut in the field and thus reducing the energy required for produced water handling at the surface.

This paper will demonstrate the key Front End Development Management challenges, project risks/opportunities, stakeholders and interface management along with key steps made to efficiently manage validate/de-risk the proposed concepts before the full field implementation driven by Decision Quality (DQ) exercise. Moreover, it will demonstrate the capital efficiency journey to improve project competitiveness through an integrated subsurface and surface efforts along with optimized contracting strategy.
Innovative Well Pad Design to Address Field Congestion Challenges and Cost Optimization
Authors: Calvier Rémi , Ségui Emmanuel , Pilipenko Alexandre , Zykova Elena , El Hadidy Khaled , El Sonbaty Ahmed , Al Jabri Bashaer
Published: November 2024

Mature field congestion is introducing challenges for future developments on surface and subsurface aspects.

The objective of this paper is to share ADNOC Onshore and TotalEnergies’ s combined effort and experience in mitigating the surface and subsurface congestion issues thanks to an innovative and cost-effective revision of the well pad concept.

The different types of existing Mature Field well pads were screened and the typical large Well Pad, providing full flexibility at the project level, was selected for analysis and further optimization to ease its implementation in surface congestion context.

The initial step was to assess the key drivers for the current well pad layout. Collected data were used as a basis to design a new pad concept considering rig fleet capabilities and best engineering practices for similar facilities. Considerations were made regarding the possibility to drill with any rig from the existing AON fleet and the requirement to minimize production shortfalls during well intervention.

Downhole congestion was also looked at, relying on specific simulations performed in various configurations.

In the pad utility area, it was found possible to achieve a significant footprint reduction by applying different design principles. Large volume of piping, valves & instrumentation were removed from the Wellbay area (moved to manifold area) and a culvert concept was implemented to accommodate well flowlines. Well pad shape was optimized by relocating the utilities area close to the well bay area.

Minimal WH spacing was assessed considering 2 types of rigs (one skidding and one non-skidding). The optimum WH distance was found to be 15m considering optimization of drilling operations, ability to cap the well and possibility to perform Work Overs with a drilling rig. It was demonstrated that distance could be reduced to 10m if smaller WO units were made available.

Considering downhole congestion only, simulations showed that WH spacing could be reduced to less than 5m and still be able to drill any well with no significant impact on cost and duration. Specific drillability issue on new wells were also studied and resolved.

Advantages of such a novel well pad design are: Overall footprint reduction by 60% (divided by 3) without major compromise on initial well pad designing criteria'sSignificant Capex savingsMassive reduction of piping length and hydrocarbon inventory (at least 30% reduction)Minimized time for preparation of WO & equipment re-installation after WOFaster drilling operations when skidding rig can be used (batch drilling)
Deployment of Self-Healing CO2 Resistant Cement for Carbon Capture and Storage Wells in Eastern Australia
Authors: Azwar C. , Alsaman M. , Veisi M. , Vang G. , Boggon P. , Narainasamy H. , Nguyen K. T.
Published: November 2024

Carbon capture and storage (CCS) is a vital technology in the fight against climate change. Eastern Australia is an important site for CCS activities where one of the operators is starting a CCS project with target to store 1.7 million metric tons (MMT) of CO2 per year, ensuring enhanced safety and permanence in the same reservoirs that have securely held oil and gas for millions of years. This paper explores the benefits of deploying novel cementing technology in CCS wells in Eastern Australia.

CO2 injection leads to a corrosive environment, which can cause cement sheath degradation. This paper presents the decision-making process used in selecting a suitable cementing system for the CO2-rich environment post-injection, and the first-time application of a self-healing and CO2-resistant cementing system in Australia. The operator is committed to safer operations throughout the life of the well by providing long-term well integrity for the CCS wells. The failure of cement sheaths due to the degradation of conventional Portland cement in a CO2 corrosive environment can lead to significant environmental risks.

The newly developed, self-healing CO2-resistant cement can withstand the effects of carbonation, making it superior compared to conventional cement systems in a CO2 environment. The deployment of this self-healing CO2-resistant cement system technology for the CCS wells in Eastern Australia has the potential to significantly improve wellbore integrity. This technology offers several benefits, including improved resistance to mechanical stresses and vibrations, resistance to chemical attack, and low permeability. In case of loss of the integrity, when the cement sheath is exposed to CO2 leaking fluids, it has the capability to self-heal and restore the long-term well integrity. Several crucial challenges were addressed for successful delivery, including the remoteness of Eastern Australia, limited accessibility to the location, job frequency, and handling at the third-party uniquely equipped blending facility. All challenges were addressed through rigorous quality control processes developed from extensive laboratory testing and comprehensive blend lifecycle management. Post-job result analysis included running wireline logs to confirm the annular barrier. Cement evaluation logs outcomes were excellent and exceeded expectations. Overall, the deployment of novel self-healing CO2-resistant cement system technology for the CCS wells in Eastern Australia ensures safer, more environmentally responsible CCS operations.
Experimental Study on Carbonated Water Flooding Enhanced Volatile Reservoirs Recovery Based on NMR Technology
Authors: Pan Yue , Liu Huiqing , Tang Jiawei , Zhou Song , Luo Chen , Wang Zuochen , Liu Renjie , Chen Pengyi
Published: November 2024

Volatile reservoirs possess intricate pore-permeability structures and high connate water saturation. Water flooding development is impeded by a strong water-lock effect, while gas injection development faces challenges with significant gas channeling, resulting in a low recovery rate. To address these issues and capitalize on the synergies between water and gas flooding, this study explores the utilization of carbonated water (CW) flooding to enhance the recovery factor in volatile reservoirs.

This study investigates the feasibility of CW flooding in a practical volatile reservoir in Kazakhstan. Employing online nuclear magnetic resonance (NMR) displacement technology, we systematically explore the impact of different displacement media (formation water, surfactant, and CW) on the recovery factor in volatile oil reservoirs. Additionally, through the integration of high-pressure mercury data with NMR T2 spectra, we ascertain the lower limit of pore diameter under different displacement methods. Finally, NMR imaging is applied to analyze the oil recovery and core microscopic pore throat producing characteristics within the rock cores.

Analysis of converted NMR T2 spectra reveals that conventional water flooding and surfactant flooding are more effective in producing crude oil in microscale micropores and microscale macropores, facing challenges in nanopores and submicron pores. CW flooding compensates for the limitations of water and surfactant flooding in producing crude oil from nanopores and submicron pores. Further data processing allows for the calculation of recovery rates and lower limits of pore diameter for different displacement methods. The pore diameter lower limits for conventional water flooding and surfactant flooding are approximately 0.1 |-im. with CW flooding exhibiting a lower limit of about 0.08 ^m. The recovery rate for CW flooding is approximately 5% higher than the other two displacement methods. Moreover. an unexpected observation from core imaging reveals that. for fractured cores. regardless of the displacement method. primary producing predominantly occurs around the fractures. As displacement progresses. crude oil in the matrix migrates towards the fracture ends. resulting in the producing of matrix oil.

Through a series of online NMR displacement imaging experiments. we investigated the impact of conventional water flooding. surfactant flooding. and CW flooding on the oil recovery and core microscopic pore throat producing characteristics in volatile reservoirs. The study determined the feasibility of CW flooding to improve the recovery efficiency of volatile reservoirs. presenting promising application prospects. Moreover. it is considered an environmentally friendly method for reducing greenhouse gas emissions.
Simulation of the Triple Completion-Gas Downhole Water Sink-Assisted Gravity Drainage Process through the Re-Injection of Petroleum Associated Gas (PAG)
Authors: Sadkhan Rawaa A. , Almansor Alzahraa M. , Al-Mudhafar Watheq J. , Javid Khalid , Rao Dandina N.
Published: November 2024

The ongoing production of oil results in a gradual depletion of reservoir pressure over time. This decline in pressure persists until it reaches a threshold at which the reservoir can no longer yield hydrocarbons through primary recovery methods. Therefore, the implementation of secondary recovery techniques is necessary to streamline pressure maintenance operations. This intervention mitigates the pressure decline for a limited period, repeating the process until the reservoir no longer generates hydrocarbons through secondary recovery techniques. Therefore, we employ tertiary recovery strategies as the last resort to enhance oil recovery from the reservoir. In this paper, we reconstructed a compositional reservoir simulation model to simulate the use of Petroleum Associated Gas (PAG) for re-injection in clastic reservoirs, surrounded by strong water aquifers, with the aim of maximizing oil production and minimizing water cut to the greatest extent possible. We specifically employed the Triple Completion Gas Downhole Water Sink Assisted Gravity Drainage (TC-GDWS-AGD) process on the Upper Sandstone member to improve cumulative oil production and reduce water cut. The TC-GDWS-AGD process places a 7-inch casing diameter and two horizontal completions, one for water production beneath the water-oil contact and the other for oil production within the high oil saturation oil zone. A packer isolates both completions from each other. Additionally, a packer perforates the top vertical annulus for gas injection at the reservoir's top, forming a gas cap and mitigating pressure depletion.

The results showed that the DC-GAGD had a significant increase in the cumulative oil (24.5 MMbbl), while the TC-GDWS-AGD achieved similar results by an amount of 23.4 MMbbl, which is nearly 5 MMbbl more than the primary scenario of 18 MMbbl. As for the water cut, DC-GAGD showed a decrease in the first days, reaching 70%, but after a short period, the water cut would rise again as a result of the continued gas injection, while TC-GDWS-AGD showed better results and for a relatively longer period of time compared to DC-GAGD, although the water cut decrease in it was 80%. It was evident that the reservoir could not sustain production for 10 years at a rate of 10,000 barrels per day. Therefore, we investigated if the TC-GDWS-AGD process could significantly mitigate the tendency of water cresting and reduce the water cut in oil production wells to low levels, especially when we reduced the strength of the maximum oil production to the appropriate levels of the current reservoir capacity, which is 2000 STB/day However, oil recovery is lower than in other cases with higher constraint values. Therefore, we should conduct an optimization to determine the optimal levels of constraints that yield the maximum oil production and the minimum water cut.
Evaluation of Residual Oil Zone Development in a Mature West Texas Carbonate Reservoir
Authors: Alobeidli A. A. , Alqallabi S. A. , Khan S. A. , Hixon E. S. , Hameed A. , Jackson J. , Nandi A.
Published: November 2024

West Texas has long been known as a showcase for successful post-waterflood (tertiary) recovery by CO2 flooding of mature waterfloods in conventional oil reservoirs. However, a large oil resource exists in the form of Residual Oil Zones (ROZs) that have been more economically challenging to develop compared to the familiar Main Pay Zone (MPZ). The conventional MPZs are producible at a feasible cost. As these CO2 floods are becoming very mature and the production is continuously declining, ROZ is becoming attractive enough to be considered and evaluated as a development opportunity.

The subject field (Means) has been producing for the last several decades with nearly half of Original Oil in Place (OOIP) residing in the untapped ROZ. This is a light oil for which CO2 has already been shown to be an effective miscible displacement injectant. Oil production from the MPZ has been in steady decline and therefore, a decade ago, several wells were drilled through the ROZ layers to gather additional data. Since the production was commingled with the MPZ and given the vertical heterogeneity, the ROZ performance was less than expected with the recovery being less than 1% after 10 years of CO2 injection. Hence the idea of utilizing dedicated wells in ROZ was evaluated by conducting this simulation study.

This study was commenced by gathering all the recent log, core, and injection/production data and construction of a rigorous ROZ geologic model. Special consideration was given to the location and extent of vertical barriers as well as location of high-perm layers to adequately capture their effect. A section of the reservoir comprising of nine 5-spot sectors was selected for a scoping simulation study. Both vertical and horizontal wells (dedicated to ROZ only) were evaluated with various well spacings. Sensitivities were also conducted with different Water Alternating Gas (WAG) cycles, continuous initial gas injection followed by WAG cycles, and with gas injection only.
Advanced Lightweight Thixotropic Cement Slurry (ALWTC) First Time Worldwide Application in a Primary Cementing Across Natural Fractured Limestones
Authors: Ramadan A. , Salazar J. , Sajid M.
Published: November 2024

Lost circulation while cementing intermediate sections across the Umm er Radhuma (UER) Formation, a naturally fractured limestone formation in UAE, is technically challenging and has financial impacts, including nonproductive time and remedial operational expenses. All fields in UAE encounter severe lost circulation while drilling UER Formation and cementing this section using lightweight slurries to isolate the zone and mitigate losses is a paramount task which requires several post-top jobs to provide zonal isolation of the casing.

ALWTC technology was developed in the UAE as a lost circulation solution to reduce and mitigate losses across vugular and naturally fractured formations during drilling. But wells having the same or more complex loss scenarios during primary cementing where standard lost circulation materials and conventional lightweight slurries are used, have limitations. The ALWTC solution was evaluated and modified to be applied with the same lightweight technology currently used in primary cementing but enhanced with a specific thixotropic agent. An identified risk is the fast gel development (thixotropic behavior), a high risk that can compromise the cement placement in primary cementing, especially in jobs where large volumes are used.

Smooth execution with well-coordinated events and best practices were deployed to ensure excellent execution without any health, safety, and environment or service quality incidents. During the first job, partial to full returns were observed, achieving cement to surface, which was our target. On one top job, only 5 to 6 bbl. of slurry were pumped, compared to 300 to 400 bbl. before. This saved 3 days of rig time and USD 25,000 of additional cost and services for the operator; additional jobs performed with similar performance. It was concluded that ALWTC is possible and suitable for primary cementing jobs across vugular and naturally fractured limestone formations. Cement evaluations also showed remarkable results across the UER and Simsima formations, compared to the normal slurry design that was being used before.

ALWTC is a technology developed locally in the UAE for UAE cementing challenges across vugular and/or naturally fractured limestone formations. This technology has immense potential in the Middle East where losses across limestone formations are some of the biggest challenges and cementing to provide the required zonal isolation is a must.
Multiphase Fluids Performance Ratio Analysis of ICD/AICV to Analyse the Multiphase Mixture Behaviour of Oil-Water Mixture and Oil-Gas Mixture During Production in Carbonate or Sandstone Reservoirs
Authors: Bjerke A. , Ismail I. Mohd , Mathiesen V.
Published: November 2024

In today's engineer's toolbox, a variety of inflow control technologies exist that can help to achieve the targets to enhanced oil recovery. Characterizing difference type of inflow control technology especially that performed during the well lifetime are challenging due to the fluids phase change during the well life. The nature of porous media, and complex interaction of fluid and rock in the reservoir often lead to mixture flow during most of the well life during production phase. Early water and gas breakthrough increase the challenge of understanding the mixture behavior flow from the reservoir to the well. Different inflow control technologies are used to enhanced oil recovery and choke the unwanted fluids (water/gas) compared to oil. It is essential to understand the performance of inflow control technology during the multiphase mixture production. The Fluid Performance Ratio (FPR) analysis for single phase flow has been presented in a paper previously. In this paper the multiphase mixture fluid methodology and workflow have been developed to compared different type of inflow control technology completion to understand the capability to reduce unwanted water and gas production in multiphase flow along the wellbore in the reservoir. Different inflow control technology and its flow performance are a function of both density and viscosity. The fluid composition affects the multiphase flow behavior differently for various devices, i.e., the pressure drop for mixture oil, water, and gas. Different designs have been tested in laboratory with single phase and multiphase flow that replicates downhole operating conditions. The multiphase fluid performance ratio will compare the performance difference in choking of multiphase fluids mixture for oil/water and oil/gas and express the multiphase fluid performance ratio in percentage. Experimental flow loop results illustrate a significant difference in multiphase behavior of oil/water and oil/gas between conventional ICDs and AICVs. AICV with dynamic flow area shows more effective control of mixed fluid during breakthrough resulting in improved oil recovery and limiting the unwanted water and gas more effectively. Case studies shown and demonstrating the mixture production behavior. Comprehensive guidelines on the multiphase fluid performance ratio analysis have been developed to compare different type of inflow control technology completion to understand the capability in multiphase fluid mixture to reduce unwanted water and gas production along the wellbore in the reservoir. The continued development of a new characterization method for multiphase flow performance ratio has helped to unveil the benefits of characterizing and differentiating between inflow control technologies.
Analyzing the Levelized Cost of Hydrogen: Leveraging Machine Learning for Evaluating Production Pathways
Authors: Ezechi C. G. , Sekar L. K , Okoroafor E. R.
Published: November 2024

This study examines the economic viability of producing hydrogen by various routes, paying attention to the hydrogen colors that are less prominent in literature. The analysis was done by comparing the levelized cost of hydrogen (LCOH) for eleven hydrogen production pathways. Predictive analysis for hydrogen production rates was also carried out using an artificial neural network (ANN) model. The data was collected using a literature-based methodology which considered several factors, such as feedstock costs, operating expenses, and capital expenditures. The study showed that the LCOH varies greatly depending on the production pathways. Due to its more modern technology, hydrogen obtained from fossil fuels (black/brown, gray, and blue) is usually less expensive than hydrogen derived from renewable energy sources (green, yellow). On the other hand, blue hydrogen requires carbon capture technology, which makes the operating costs associated with it higher. Aqua hydrogen stands out with the lowest levelized cost of $0.23/kg hydrogen produced, but environmental concerns from oil sand extraction and emerging technologies like orange hydrogen need further consideration. The ANN model was developed based on key hydrogen production parameters, and its performance was evaluated using metrics such as the proportion of variance (R-squared), mean square error and root mean square error. The R-squared result for the test data set was 92% (R2=0.92), showing the model's high predictive accuracy. This study is unique in two ways: first, it shows significant differences in LCOH across several hydrogen colors, with aqua hydrogen becoming the most economical choice. Second, it shows how machine learning can be used to find cost-cutting measures and optimize hydrogen production processes through various methods. Further research is required to address the lack of real-time production data, investigate the environmental effects of these production processes, and improve the accuracy of developed models.
Enhancing CO2 Dissolution Storage and Analyzing Leakage Risks in CCUS Using Microfluidic Technology
Authors: Chen Zheng , Li Lei , Su Yuliang , Hao Yongmao , Wang Wendong
Published: November 2024

In the process of CCUS, it is crucial to improve the efficiency of CO2 sequestration and analyze related leakage risks. This study aims to design experiments and evaluation methods using microfluidic and SEM technologies to investigate the effects of different agents on enhancing CO2 solubility storage under varying pore size conditions and to analyze the microscopic impacts of CO2 dissolution on rock minerals. The experimental results show that the addition of solubilizing agents reduces CO2 erosion, making dissolution less evident, and the resulting mineral precipitates fill some of the pores, reducing CO2 leakage paths. Triethanolamine exhibits a more significant solubilizing effect at higher pressures, while the effectiveness of solubilizing agents decreases with smaller pore diameters. Isopropyl citrate shows optimal solubilizing effects under low-pressure gaseous conditions. Under high-pressure supercritical conditions, smaller pores enhance the solubilizing effect, reaching up to 201.9%.
Development of Novel Predicting System to Forecast Ocean Spot and Forward Prices Using Machine Learning
Authors: Almaazmi Jawaher , Alzaabi Mohamed , Naidu Dr Kiran
Published: November 2024

Executive Summary

Project Implementation
Distributed Temperature Sensing Using Tapered Monobore Completion for Extended Reach Wells
Authors: Barragan E. , Varma E. , Wibowo S. , Jimenez A. , Al Wahedi O. , Zafar O. , Khaled M. , Aljasmi S. A.
Published: November 2024

The oil industry faces several challenges when performing Lower Completions in Extended Reach Wells (ERW), such as increased friction factor, higher tortuosity, and so on. The introduction of Tapered Monobore Completion (TMC) for Extended Reach Wells (ERW) marks a significant advancement in the field of reservoir development. This paper explores the process of design and benefits of TMC, particularly in conjunction with Distributed Temperature Sensing (DTS) technologies and Limited Entry Liner (LEL) stimulation technique, to enhance production rates, reduce operational costs, and improve reservoir management.

A new method was devised after several trials of running Distributed Temperature Sensing (DTS) Completions in longer horizontal wells with conventional 3-1/2″ completion in horizontal hole section. The Monobore Completion was adjusted to a tapered 4-1/2″ + 3-1/2″ in horizontal hole and the number of swell packers was reduced. DTS completion with carrier using Limited Entry Liner (LEL) was deployed with a length of more than 6350 ft in a carbonate reservoir in the Middle East. Various simulations of torque and drag analysis were performed to determine the optimal configuration of the Tapered Monobore Completion.

After the first successful design and deployment of a well in the long horizontal hole, two more wells have been finished and more are planned in other reservoirs of the Field. Also, the Tapered Monobore Completion design is being considered for other Fields in the same area. The successful deployment sets a standard for best practices and improvements in well completion. It shows that TMC can work in ERW and can greatly affect operational efficiency and cost-effectiveness. The results and methods from this project are expected to shape future designs and operations, helping the oil and gas industry's skills in reservoir use and management. Combining Tapered Monobore Completion with DTS systems gives operators real-time reservoir monitoring abilities. This combination helps operators make informed choices for reservoir management, possibly increasing hydrocarbon recovery through accurate and timely actions.

TMC has a streamlined design that needs fewer parts and less time to install, making it more affordable than conventional completion methods. This lower cost is helpful not only in the immediate term but also for the long-term profitability of well operations. The Monobore design is simple and allows for easier access for well interventions and maintenance. This access is crucial for reducing the time and costs of these operations, and improving operational efficiency.
An Innovative Characterization Method for Recovery Factor Quantification of Horizontal Shale Gas Well in Sichuan Basin, Southwest China
Authors: Yu Wei , Wu Jianfa , Huang Haoyong , Liu Chuxi , Sepehrnoori Kamy
Published: November 2024

This study presents a comprehensive methodology for evaluating the performance and economic viability of two shale gas wells in the Sichuan Basin, Southwest China. A hydraulic fracture simulator was utilized to model fracture propagation, incorporating a 3D geomechanics model and natural fractures. The fracture model was calibrated using real pumping pressure data, and the calibrated fracture geometry was integrated into a reservoir model using the Embedded Discrete Fracture Model (EDFM) method for history matching with field production data. The study introduces a new method to calculate the drainage recovery factor, providing a more accurate estimation of hydrocarbon recovery. Long-term production potential was assessed through a 20-year Estimated Ultimate Recovery (EUR) analysis, and the Drained Reservoir Volume (DRV) was calculated to understand reservoir depletion over time. The results indicated significant differences between traditional recovery factor estimates and those obtained using the new method, underscoring the importance of advanced modeling techniques in capturing the complexities of reservoir behavior. Additionally, an economic analysis was conducted, revealing that one well was significantly more profitable than the other, highlighting the value of integrating technical and economic evaluations in shale gas development projects.
Enhancing Upstream Operations: Hybrid Approach for ESP Failure Prediction in ADNOC’s Assets for Operational Excellence and Digital Progress
Authors: Hernandez C. , Asif U. , Caicedo S. , Al Nuaimi D. , Bakhti S. A. , Guzman R. , Aguilar H. , Alsaeedi K. , Al Radhi M. , Alhashmi Z. , Alhammadi A. , Abdelkerim A. , Chelligue T. , Almadhoun W. , Palomino C. , Ayoubi R. , Hammo A. , Arnaout A. , Penubarthi S.
Published: November 2024

This paper proposes a transformative approach in Electric Submersible Pump (ESP) management, aiming to predict failures and prevent ESP downtimes ahead of their occurrence. The goal is to build a reliable tool that assists in the decision-making process for preventive ESP replacements. This initiative not only enhances planning through accurate rig allocation and inventory optimization but also minimizes deferred production by establishing a zero-failure intervention strategy.

The predictive model operates on an assembly that considers a Real-Time data acquisition system, core predictive model algorithms, and automated engineering workflows. This ensemble is designed to process both real-time and historical data, complemented with surface parameters to accurately forecast ESP failures while providing probabilities of occurrence. By integrating machine learning techniques with traditional physics and statistical analysis, the model provides critical insights into ESP health, thus enabling proactive maintenance and operational planning. Applied across diverse ESP setups, this proactive strategy not only sustains production but also enhances operational flexibility.

The ESP predictive model provides the information that enables the establishment of a cohesive predictive maintenance solution that effectively unifies the principles of data science with operational technology. The implementation has notably improved the reliability of ESP operations by providing petroleum engineers with the tools to maintain continuous production. The evidence gathered during the pilot phase reveals the system’s proficiency in anticipating ESP failures, leading to a significant reduction in unplanned shutdowns and maintenance costs. The success of this project emphasizes the strategic value of predictive maintenance in realizing operational efficiency, enhancing profitability, and fostering a digitally empowered corporate culture within ADNOC’s upstream sector.

This paper introduces a groundbreaking approach to predictive maintenance in the oilfield, enhancing established methodologies with a comprehensive, data-driven strategy that bonds machine learning, physics, statistics, and real-time operational data. This novel method not only advances ESP management but also sets a new standard in failure prevention and operational optimization while improving decision-making by providing probabilities of occurrence.
Innovations in Downhole Monitoring Technologies and Applications: Seismic Exploration with Real-Time Hybrid Coiled Tubing Technology and DAS VSP Driving Sustainable Progress
Authors: Gaeta M. , Iervese G. , Stanek F. , Ellis J. , Khayyat A.
Published: November 2024

The ongoing transition towards sustainable energy sources is driving operators to explore renewable energy solutions. "Green" or renewable energy sources are characterized by their ability to regenerate at a rate equal to or greater than their rate of consumption, ensuring a continuous supply without exhausting natural reserves, and significantly reducing environmental impact. Geothermal energy stands out as a promising renewable resource that can significantly reduce dependence on conventional hydrocarbons such as oil and gas. Although natural gas is sometimes labeled as the cleaner hydrocarbon, geothermal energy is a more sustainable and renewable option. This resource has a potential to generate both electricity, where reservoir temperatures exceeding 100°C can produce steam, and heating through low-temperature geothermal systems. Low-temperature geothermal systems are more accessible compared to their high-temperature counterparts, and offer significant potential for applications such as district heating and the provision of domestic and industrial hot water. However, the challenge lies in optimizing the sustainability of these operations and minimizing the risk of unsuccessful exploration, particularly in identifying the geological formations capable of matching the project’s objectives.
Application of Agro-Waste Polysaccharide-Carbonate Blended Bridging Agent: A Dual Solution for Carbon Footprint Reduction and Wellbore Stability Improvement in Offshore Assets of India
Authors: Pandey Ashutosh , Singh Kulwinder , Dhakate D. M. , Kumar Neeraj , Gautam Amitosh , Verma J. S. , Singh Ratan
Published: November 2024

This paper is aimed to investigate effectiveness of smartly blended agro-waste polysaccharide-carbonate bridging materials which was used in improving wellbore stability and drilling efficiency in brownfield environments with complex well bore geometries. This effectiveness of bridging agent also contributes to carbon reduction.

Reservoirs in brown fields are depleted and the intricate well profile poses significant challenges for maintaining wellbore integrity during drilling operations. This challenge was addressed by incorporating a smart blend of agro-waste polysaccharide-carbonate based bridging materials, with varying particle sizes, into the drilling fluid. Study was conducted on 34 wells for effectiveness of network structure and the bridging efficiency.

Study shows that by pumping over and around 20-25 ppb of bridging material into the drilling fluid system there was decline in seepage losses by 51.89%. Bridging materials enhanced hole cleaning by increasing the gel strength and yield point of the drilling fluid which reduced both Equivalent Circulating Density and fluid loss thus leading to efficient drilling operations and reduction in non-productive time by 46%.

The bridging material’s ability to form a strong mud cake with good sealing properties enhances wellbore integrity throughout the drilling process, minimizing mud losses and potential environmental impact. Also, the compatibility of cellulose-carbonate bridging material is both in oil-based and water-based drilling fluid system.
Time-Preserving Tomography in Structure Mapping: A Case Study of a Deep Gas Reservoir, Offshore Abu Dhabi
Authors: Hong Y. , Cambois G. , Al Neyadi A. A. , Cowell J. , Aljaberi F. , Al Kaabi A. S. , Puri A. K.
Published: November 2024

A deep gas reservoir in an offshore field, Abu Dhabi presents a unique challenge in structure mapping due to significant misties encountered when utilizing both Pre-Stack Time Migration and Pre-Stack Depth Migration seismic data. Rapid variation of velocity in horizontal and vertical directions makes the mistie issue very challenging especially for the wells not included during the velocity model building for PSDM. To address the challenges, improve the structural interpretation and velocity model of the deep gas reservoir, a novel workflow of time-preserving tomography (TPT) has been applied.

TPT is a technique that preserves the travel times of seismic events while updating the depth domain horizons and interval velocities by ray tracing. It uses a modified version of the Dix formula that accounts for the vertical and lateral variations of the velocity field. The process may need to be iterated several times until the velocity model and horizons that meet your expectations are obtained. TPT was applied to a deep gas reservoir using seismic data from a 3D survey and initial horizons and velocity models derived from well logs and conventional tomography.

The updated horizons and velocity model by TPT showed better consistency with the well data and seismic reflectors than the initial models. The difference between the initial and updated velocity model reveals a polygon-shaped area with significant velocity anomalies, which corresponds to the fault system or a carbonate buildup in the reservoir. The structural mapping and velocity analysis by TPT has enhanced the understanding of the reservoir geology and heterogeneity.

This paper presents the first application of TPT to a deep gas reservoir, within the offshore Abu Dhabi oilfields, demonstrating its advantages over conventional structure mapping in updating velocity models and improving the depth domain interpretation. TPT is a robust and efficient workflow that can be applied to other complex reservoirs with similar challenges. The case study highlights the method's ability to reconcile discrepancies and provide a more reliable geological framework for exploration and development strategies.
Supply Chain Management with AI
Authors: Hamadi Khaled Al , Ekambaram Somasundaram
Published: November 2024

Supply chain management (SCM) in the downstream gas sector involves intricate operations that are pivotal for the efficient flow of materials, from procurement to delivery. The accurate prediction of material reservations is crucial in this process, ensuring that the right materials are available at the right time. Historically, these predictions have been performed using traditional statistical methods and human judgment, often leading to inefficiencies such as overstocking or stockouts, both of which have significant cost implications.

With the rapid advancement of Artificial Intelligence (AI), there has been a paradigm shift towards using data-driven approaches to optimize SCM processes. AI and machine learning models can analyze vast amounts of historical data to uncover patterns and trends that are not immediately obvious, leading to more accurate forecasts and more efficient operations.
Successful Implementation of Azimuthal Accuracy in Completions with Fiber Optic Cable to Optimize Productivity and Injectivity
Authors: Chinchayan Gustavo A. , Breiki Ibrahim Al , Sabari Sulaiman Al , Taiwani Mohammed Al , Ahmadzadeh Peiman , Hinai Khalil Al , Bahri Bader Al , Nadhari Nasser Al , Kamali Mohammed
Published: November 2024

Oriented perforating has been a challenge in the oil industry for different applications from vertical to horizontal wells. The introduction of fiber optic cable in completions allows better well data and reservoir monitoring. Assurance and reliability on technologies to maintain fiber optic integrity while perforating remains a concern in the industry. The application began covering from narrow azimuth to an expanded circumferential coverage in the borehole. The superior circumferential coverage was possible with the development of new technology. Increasing azimuthal exposure of the borehole requires confidence on accuracy of the instrumentation.

The methodology implemented together with technology available should provide positive results securing the asset investment and maintaining the integrity of the fiber optic cable.

In this article, different approaches are described for oriented perforating with fiber optic installed along the casing. The document outlines both a mechanical orientation with tubing conveyed perforating and oriented perforating with wireline.

The mechanical orientation with tubing conveyed perforating starts when casing and fiber optic is installed on the well. A special permanent casing device is designed together with a retrievable running tool conveyed with guns that will lock in the adequate azimuth away from the fiber optic cable. A standard correlation survey is required to verify the depth position of the special device in the casing.

The oriented perforating with instrumentation conveyed with wireline uses an azimuthal oriented tool or a gyro device. The gyro is used for wells with deviation less than five degrees. The azimuthal oriented tool is used with wells with a deviation larger than five degrees. The instrumentation locates the fiber optic cable angle position with respect of the high side of the hole or angle position with respect of magnetic north. In order to help the location of the fiber optic a special strip is installed together and below the fiber optic cable. Prior perforating, this angle position is verified. The verification assures reliability of the whole system avoiding damage on the fiber optic cable.

The azimuth coverage has risen from one hundredth and thirty five degrees to two hundredth and twenty five degrees. The estimation of azimuth coverage with instrumentation is about two hundredth and seventy degrees. Furthermore, the methodology with wireline conveyance could improve above mentioned values.

In summary, this article describes procedures, difficulties observed on actual services and successful implementation of techniques that leads to successful oriented perforating with larger circumferential coverage.
Supply Chain Network Optimization & Simulation Model Digital Twin
Authors: Almaazmi Jawaher , Alzaabi Mohamed , Naidu Kiran
Published: November 2024

Executive Summary

About Borouge

Borouge is a leading petrochemical company that provides creative plastics solutions for a wide range of industries. Established in 1998, Borouge is a joint venture between the Abu Dhabi National Oil Company (ADNOC), one of the world’s leading oil and gas companies and Austria based Borealis. petrochemical and plastics manufacturing plant is in Al Ruwais at about 250 km west of Abu Dhabi. In addition to our production site in Abu Dhabi, Borouge also has a Compounding Manufacturing Plant (CMP) in Shanghai which compounds resins from the Ruwais plant specifically for the Asian automotive industry.

Supply Chain Design & Planning Model

Need

As a world leader in polymer solutions, we required an established digital twin for its supply chain planning (more specifically logistic network optimization & simulation) and configurable assets. The initial transformation process focused on UAE production site, global supply chain network and operations, with an emphasis on cost and service levers. The need was to develop a digital twin within the first 8 months of the project. The solution was to be used as a strategic tool to define the optimal network. This was to be done by selecting the optimal Inventory Holding Point ("IHP") to serve customers based on associated costs, capacities and lead times.

Key Objectives

The primary objective of the Supply Chain Network Optimization & Simulation model was to optimize the Inventory Holding Point ("IHP") selection between Al Ruwais and the destination port to minimize network cost leading to better

Development Brief

The model was developed using:

Outcome

A Network Optimization Model utilizing applications like Supply Chain Guru X & Data Guru was created that lead to following outcomes and certain capabilities for the end user:

Results

This information has been utilized by various departments for orders executions. It is helping the business to better analyze data to optimize operations, enhance customer experience, and reduce costs.

Second-Level Heading.
Drilling the World's First Fully Sequestered Co2 Injection Well: Challenges, Execution and Lesson Learned
Authors: Arbadov Gurbandurdy , El-Husseiny Mahmoud , Sumaida Ali , Anwar Mohamed , Al Huwait Nada
Published: November 2024

According to the Intergovernmental Panel on Climate Change (IPCC) and the International Energy Agency (IEA), carbon capture and storage (CCS) is crucial for meeting climate change targets. CCS is a key part of the UAE's sustainability strategy and its commitment to achieving net-zero emissions. The field operator initiated a major CCS project focused on permanently storing CO2 in carbonate deep saline aquifers. Following a rigorous feasibility study, the first CO2 injection well was drilled. The aim was to gather the data essential for asset management, ensuring wellbore integrity in CO2-rich environments, and advancing real-time monitoring capabilities.

The project employed several innovative techniques and methodologies to achieve its objectives. For the first time in the UAE, a permanent fiber optic cable was deployed behind a 7" casing to enable enhanced real-time monitoring. The project utilized CO2-resistant non-Portland cement globally for the first time to ensure the long-term integrity of the wellbore. Six coring runs were completed across intended cap rocks and target water reservoirs, and water samples were collected from the interest zone under expected loss formations. A TCP gun was used to perforate 600 feet of 9 5/8" casing in one run with a 100% firing success rate. Additionally, 3 ½" CRA tubing with dual fiber optic cables was run, and a deep-set surface-controlled subsurface safety valve (SSSV) was installed in the tubing. Custom wellhead modifications were made to accommodate fiber optic cable exits, and fit-for-purpose operational procedures were developed for the permanent deployment of fiber optics behind the casing. Feasibility studies, risk assessments, and de-risking strategies were integral to the project's execution.

The project reached a significant milestone by achieving 100% data gathering, meeting the asset's requirements, and marking several groundbreaking achievements along the way. One notable accomplishment was the successful mini frac operation across hard cap rock RUS, a first-of-its-kind operation in the UAE. This operation validated the feasibility of this formation to act as a caprock, crucial for ensuring the safe injection and containment of CO2. Moreover, the project was executed with zero HSE (Health, Safety, and Environment) incidents.