bluuebunny/crossref_metadata_2025_split huggingface dataset:
Production Enhancement in Intermittent Gas Lift Wells Using Sweeping Pipe Bend - Successful Case Histories from Various Onshore Fields in India
Authors: Yadav Mahendra Prasad , Malhotra Sanjay Kumar , Kumar Avinav , Devshali Sagun 
Published: December 2021

Abstract

Objectives
In wells which are producing on intermittent gas lift (IGL), the injected gas cannot sweep the entire liquid volume to the surface from the bottom of the tubing as there is continuously some fluid falling back in the tubing. The fallback can be described as the difference between the volume of the slug at the start of the gas injection and the volume of the actual produced slug at the surface. This fallback of liquid happens due to the fact that the gas has a tendency to flow through the liquid slug and letting the liquid to fall. The intensity of the liquid fallback increases more when there is increase in back pressure at wellhead. In order to minimize this liquid falling back in wells on intermittent gas lift, the sweeping pipe bend technology has been used in the various onshore fields operated by ONGC which has resulted in substantial gains and has been brought out in the paper.

Process
Gas break through and fallback are affected by three factors including the development of the gas bubble, the velocity of the slug flowing upward in the tubing, and wellhead restrictions caused due to presence of many 90-degree bends. To prevent gas breakthrough and to optimize the liquid fallback to minimum 5-7 % per 1000 feet of lift, it is recommended to maintain 1000 feet/min of minimum velocity of slug. Slower is the velocity of the slug which is moving up in the tubing, the longer time it takes for the gas to break through the liquid. At 1000 feet/min velocity, the wellhead restrictions can result in fallback losses due to breakthrough of gas in the well. In general, the flow path through the Christmas tree into the flowline is rather tortuous, moving first through a tee to the wing valve, then through other 90-degree ells before finally reaching the flowline. These restrictions further result in slowdown of the velocity of the slug thus resulting in more liquid to fallback and subsequently in significant production losses.

Results
In order to overcome the aforementioned problem and to reduce fallback in an intermittent gas lift well, sweeping pipe bend technology was considered and in the first phase implemented in 5 identified wells of different fields of ONGC Assets. With the help of sweeping pipe bend, the flow pattern becomes streamlined and number of 90-degree bends reduces or eliminates resulting in substantial reduction in the back pressure thus reducing the fall back. The implementation of the technology has resulted in an average liquid gain of 20.3% per well. Various guidelines for successful application of sweeping pipe bend have also been brought out in the paper.

Additive Information
650 candidate wells operating on intermittent gas lift have been identified for the implementation of Sweeping Pipe Bends. As per the analysis, the implementation of Sweeping Pipe Bend is likely to result in a liquid gain of about 1000 m3/day from these wells.
Physics Informed Neural Networks Based on a Capacitance Resistance Model for Reservoirs Under Water Flooding Conditions
Authors: Maniglio Marco , Fighera Giorgio , Dovera Laura , Stabile Carlo Cristiano 
Published: December 2021

Abstract
In recent years great interest has risen towards surrogate reservoir models based on data-driven methodologies with the purpose of speeding up reservoir management decisions. In this work, a Physics Informed Neural Network (PINN) based on a Capacitance Resistance Model (CRM) has been developed and tested on a synthetic and on a real dataset to predict the production of oil reservoirs under waterflooding conditions.
CRMs are simple models based on material balance that estimate the liquid production as a function of injected water and bottom hole pressure. PINNs are Artificial Neural Networks (ANNs) that incorporate prior physical knowledge of the system under study to regularize the network. A PINN based on a CRM is obtained by including the residual of the CRM differential equations in the loss function designed to train the neural network on the historical data. During training, weights and biases of the network and parameters of the physical equations, such as connectivity factors between wells, are updated with the backpropagation algorithm.
To investigate the effectiveness of the novel methodology on waterflooded scenarios, two test cases are presented: a small synthetic one and a real mature reservoir. Results obtained with PINN are compared with respect to CRM and ANN alone. In the synthetic case CRM and PINN give slightly better quality history matches and predictions than ANN. The connectivity factors estimated by CRM and PINN are very similar and correctly represent the underlying geology. In the real case PINN gives better quality history matches and predictions than ANN, and both significantly outperform CRM. Even though the CRM formulation is too simple to predict the complex behavior of a real reservoir, the CRM based regularization contributes to improving the PINN predictions quality compared to the purely data-driven ANN model. The connectivity factors estimated by CRM and PINN are not in agreement. However, the latter method provided results closer to our understanding of the flooding process after many years of operations and data analysis. All considered, PINN outperformed both CRM and ANN in terms of predictivity and interpretability, effectively combining strengths from both methodologies.
The presented approach does not require the construction of a 3D model since it learns directly from production data, while preserving physical consistency. Moreover, it represents a computationally inexpensive alternative to traditional full-physics reservoir simulations which could have vast applications for problems requiring many forward evaluations, like the optimization of water allocation for mature reservoirs.
Reliability Based Structural Risk Assessments and Associated Economic Gains
Authors: Atia Mohamed , Abdelkhalek Ahmed , Sarkar Anjan , Keys Matt , Patel Mahesh , Eissa Mohammed , Omar Tarek 
Published: December 2021

Abstract
Managing a large fleet of offshore structures is a dynamic process that aims at minimising risks to personnel, environment, and businesses, as well as minimising the associated Operations Expenditure. Through the collaborative efforts of ADNOC Offshore and Kent, formerly Atkins Oil & Gas, (Atkins, 2020), revised structural evaluation and integrity approaches have yielded significant cost savings. The considerable savings were associated with the elimination of the requirement for installing many new offshore structures and through reducing the subsea inspection associated efforts.
The approach for evaluating the offshore assets’ structural performance was developed based on adopting target probability of failure figures subject to each asset's consequence of failure. Accordingly, structural reliability analyses were conducted specific to each structure, where the analysis considered structure specific environmental hazard curves and failure surfaces.
Through mapping the evaluated structural probability of failure and ADNOC's corporate risk matrix's HSE Likelihood, each structure was precisely placed on the risk matrix. Furthermore, the inspection intervals and Topsides, Splash Zone, Subsea Levels I, II and III were mapped to each risk evaluation on the risk matrix.
The optimisation approach of adopting a structure specific reliability analysis and mapping with ADNOC's corporate risk matrix yielded considerable cost benefits while providing a more accurate representation of each asset's risk. As a result of the implementation of the developed process, approximately 41% of the assets got lower risk evaluation compared to the legacy approach and presented extra structural capacities that can be utilised for future expansions and eliminating the requirement for installation of new assets. As the process expanded to include asset inspections, the subsea inspection requirements reduced by approximately 43% reflecting a considerable decrease in operating costs.
A major contribution of the risk improvement is attributed to the consideration of the storm prevailing approach directions, the joint probability of wave and current magnitudes and directions, as well as the relative alignment of each structure.
The developed approaches provide a framework that allows continuous update of the risk assessment and enables executives and management to make risk-based-decision supported by a consistent measure of structural risk. This has been translated into the generation of the Structural Passports (Summary reports) clearly demonstrating the assets current risk and recommendations for mitigation measures, if deemed required.
Emission Capping & Trading, First of its Kind in ADNOC Group
Authors: Alhosani Abdulla Humaid , Humayun Nasir-ud-Din , Kannan Jawahar 
Published: December 2021

Abstract
The Spiking Gas Compressor project was installed in 2014, which reduces 65,000 tons of Carbon-di-oxide (CO2) emission annually. This was subsequently registered as a CDM (Clean Development Mechanism) project under UN convention and incidentally this was the first ADNOC project to be under this registration. The registration is the first step to claim for Carbon Credits under United Nations Framework of Clean Climate Convention (UNFCCC) scheme. No Carbon Credits were claimed under CDM since its commissioning in 2014 due to low carbon price. In 2019, we achieved the next big milestone of trading these accumulated carbon credits to an Austrian MNC. M/s MASDAR, pioneer in this field, who are also partner of ADNOC onshore in this green project, arranged an Upstream Emission Reduction (UER) buyer. The transaction is worth 65,000 tons of CO2 reduction and considerable monetary benefit. This transaction assumes significance not in terms of monetary value but a global recognition to ADNOC as a company amongst the leading players in the global arena in reducing the Greenhouse Gas (GHG) emissions.
This project is the first & largest Clean Development Mechanism (CDM) registered in Oil & Gas industry in UAE.
United Nations Framework Convention on Clean Climate (UNFCCC) recognized flare gas recovery through Spiking Gas Project as Clean Development Mechanism (CDM) project to generate Carbon Credits.
The project demonstrates the commitment and support of Abu Dhabi Government and ADNOC towards climate change mitigation measures.
Clean Development Mechanism (CDM) project demonstrated successful partnership with Masdar.
The project was converted into to UER scheme. ADNOC Onshore & Masdar arranged a Buyer. Later, in compliance to ISO 14064/65, post Validation/ Verification by external auditors brought a considerable revenue to ADNOC.
Development Wells Optimum Management Technique Coping with Production Curtailment for Stacked Oilfields Consisting of Multiple Complex Reservoirs
Authors: Lyu Hengyu , Liao Xuan , Zhou Wenyin , Lan Yukun , Peng Shudai , Li Nan , Yang Jing 
Published: December 2021

Abstract
Affected by the Covid-19 pandemic and low oil prices, OPEC members were forced to curtail production. The H oilfield in Iraq commenced production curtailment in early March 2020 and then oil production gradually decreased. By the end of 2020, production was less than one-third of the rate before curtailment. There are multiple sets of oil-bearing formations in the H Oilfield vertically. The developed oil reservoirs have a total of more than three hundreds development wells. The reservoir types are diverse, the relationship among multiphase fluids is complex, and the development methods are different. The reduction of the daily production will inevitably require a comprehensive strategy adjustment to cope with the new situation. Any intentional or unintentional shut-in has a price. Therefore, the key is how to reasonably control the production in many oil reservoirs and re-adjust the oil reservoir development plan at the minimum cost while meeting the overall changing production restriction target for each oil reservoir. In this study, the author established a simple and fast process for judging open and closed wells through years of experience in reservoir dynamic analysis and field management. Step 1: Wells are classified according to production characteristics. For pre-selected wells, some wells with unique functions that need to be opened and those that need to be closed for objective reasons should be excluded. Step 2: Conduct single well cost analysis with reference to production status. Respectively evaluate the performance of the production well under the state of opening and closing. Step 3: Establish the model with economic indicators as the objective function. According to different goals, the model established is slightly different. Step 4: Optimize the best solution based on actual needs. Solve the optimal solution under the target and optimize the number of reasonably configured wells in each reservoir. Through this process, combined with historical and current actual production conditions, different types of oil wells in all reservoirs are classified. Their priorities of reopening are evaluated to meet the needs of other production restriction targets and ensure the smooth transition of oilfield development.
Improvements on High Temperature Lithium Oxyhalide Primary Battery for Downhole Tools Power Applications
Authors: Bi Wu , Ren Jiaxiang , Cheng Peng , Wang Xu , Dunne Tim , Zhao Lei 
Published: December 2021

Abstract
Commercial lithium oxyhalide batteries have a very flat voltage curve. It is challenging to determine a battery's remaining capacity during and after powering downhole drilling tools. It is wasteful and environmentally hazardous to dispose of lightly used battery packs. Through innovations in battery cell design and electrolyte formulation, laboratory cells showed multiple voltage plateaus allowing easy estimation of remaining capacity at room temperature. Prototyped DD-size batteries validated the unique feature at high temperatures. If the batteries are used in downhole drilling and measurement tools, non-productive time may be shortened, and costs reduced over time.
Small coin cells were assembled in an inert argon gas filled glovebox. The assembled coin cell, lithium metal foil disk, carbon electrode, and other cell components were weighted to determine electrolyte weight accurately. Carbon black electrodes were prepared by coating carbon black paste on nickel foam substrate. After overnight air drying, coated nickel foam was hot pressed to 1 mm thickness at 230 °C. DD-size cells were prototyped at a battery vendor with selected cell configurations. Performance of coin cells and prototyped DD-size cells were measured during constant current discharge tests.
Discharge voltage curves of baseline coin cells mimicking commercial battery products were flat at 3.4 until sudden voltage crash at the end of discharge. Coin cells OP-33 and OP-36, with the improved design and electrolyte formula, showed two main voltage plateaus. The higher voltage plateau was around 3.85-3.60 V, and the lower voltage plateau was around 3.50-3.40 V. The sharp voltage transition from 3.60 V to 3.50 V was easy for a user or a battery management system to detect. Capacity percentage in the higher voltage plateau and the lower voltage plateau depends on the energy active chemical compositions of electrolyte. A cell design and electrolyte formulation were selected to prototype scaled-up DD-size cells. Three repeating DD-size cells were discharged at 150 °C. The overall sloping voltage curves and the obvious voltage transition between two discharge stages around 3.5 V can greatly facilitate battery capacity estimation.
As of today, there is no commercial high temperature lithium oxyhalide primary battery with such a unique feature of staged and sloping battery voltage shape for capacity estimation. Compared to capacity estimation by charge counting method utilized in some battery monitoring chips, capacity estimation based on voltage change is much simpler, more accurate, and consumes less battery energy without needs of frequent current measurement and charge calculation. Any previously lightly discharged battery pack can be easily determined whether further usage is possible for the next downhole tools power application, which saves cost and reduces battery waste.
Future Proofing the Development of Unconventional Resources in UAE
Authors: Okouma Mangha Viannet , Lazreq Nabila 
Published: December 2021

AbstractThe growth of USA shale oil and gas production over the last decade has been nothing short of phenomenal. In 2012 shale gas comprised 39% of US natural gas output, and by 2040, nearly 80% of total gas production is anticipated to come from unconventional resources. In April 2021, in the USA alone, gas production from major unconventional plays reached 83.0 BCFD and oil production was 7.6 MMBD.Driven by rising gas demand and advances in geosciences, drilling and completion technology (hydraulically fractured horizontal wells), unconventional plays have become eminent in the global energy supply, both for value and volume. The development of unconventional resources in North America was aided by governmental positive policies and taxes preferences, the readily available infrastructure, a vast service sector, advanced technologies and expertise, and general understanding of sweet spots due to numerous well penetrations.Following the above accomplishments: exploration, development, and production success in North America, particularly in the USA unconventional basins, several Majors and Independents have been trying to expand the opportunities outside of North America and other countries such as UAE, Oman and Saudi Arabia have been booking significant unconventional resources. For these reasons, the USA and Canada represent the ‘reference benchmark’ by which countries similarly endowed with shale resources can be evaluated.Abu Dhabi recently announced, in 2019 and 2020, discoveries of 160 TCF of unconventional gas, an estimated 22 billion STB of recoverable unconventional oil resources, both located onshore. These finds have pushed the UAE to the sixth position globally in terms of hydrocarbon reserves, from seventh, according to data listed by the US Energy Information Administration (EIA). Developing these resources are an integral part of ADNOC 2030 strategy of "Monetize our hydrocarbon resources" and becoming gas self-sufficient by 2030.North America achievements in unconventional resources development has triggered other countries to evaluate their unconventional resources. This has come with mixed results: failures in Ukraine, Poland and successes in Argentina. UAE has world class unconventional resource base which development raises the challenges of what practices worth replicating (PWR) need to be adopted by UAE and in turn ADNOC. Some lessons learned, thus practices worth replicating (PWR) can be tailored and adopted from the success of unconventional resources development in North America, will be described in this paper as a benchmark for progressing unconventional resources development in UAE.
The Integration of Analytical P/Z Material Balance Method with Static Modeling and Integrated Asset Model IAM to Generate Reliable Forecasting for a Giant Onshore Gas Field in Abu Dhabi
Authors: Bernadi Bondan , Pramudyo Yuni Budi , Alawadhi Fatima Omar , Belal Al Shamsi Alia Belal Zuwaid , Al Hammadi Shamma Jasem , Mohamed Ihab Nabil , Al Bairaq Ahmed Mohamed , Al Hosani Mariam Ahmed , Allam Farid , Abdullayev Azer , Roopal Allen 
Published: December 2021

Abstract
FGIIP (Field Gas Initially in Place) is one of the most essential elements in building dependable static and Integrated Asset Model (IAM). A good estimation of FGIIP will improve history matching and generate reliable forecast. The mature gas field producing under depletion mode is an ideal example where P/Z technique can fit well to re-estimate the FGIIP. Even more, the estimation is also important to narrow down FGIIP uncertainties that initially existed in static model.
Reliable FGIIP estimation is achieved by performing multiple P/Z calculations. The process involves dividing reservoir into key areas and each area is represented by individual P/Z prior to summing-up all P/Z to get the total FGIIP. Several scenarios are developed by defining key areas based on permeability variation, areal distribution and PVT behavior. The best FGIIP estimation is then fed back into the static model to generate numerous realizations considering the static uncertainties to produce the same FGIIP. Static models with realistic distribution of properties and good history match are used in the IAM model to generate forecast.
The giant onshore gas field is highly heterogeneous having permeability, lateral composition variation and dynamic interaction between wells. To ensure that the heterogeneity observed in the field is honored, multiple key areas are defined by making areal sectorization and lateral PVT variation when estimating FGIIP with P/Z approach. Communication between areas was evidenced from the sectoral P/Z. The field history matching was improved after applying the new estimated FGIIP. It was observed that the sectoral history matching both for production and pressure matches from some selected realizations built in static model resulted in better matches. Succinctly the re-evaluation of static derived FGIIP with P/Z method for the mature gas field was able to reduce the uncertainty range that initially existed. Incorporating the correct estimation of FGIIP in IAM has helped to yield reliable forecast and has enabled the asset to plan proper work programs for further field development.
Analytical material balance with P/Z is very applicable for mature gas reservoirs producing under depletion mode. The approach is worth doing to narrow down the uncertainty range that was previously calculated. Moreover, the integration of analytical P/Z with static and dynamic model (IAM) has achieved more reliable forecasting of the mature gas field to proceed with further development plan.