bluuebunny/crossref_metadata_2025 huggingface dataset:
Commercialization of Al Reyadah – World's 1st Carbon Capture CCUS Project from Iron & Steel Industry for Enhanced Oil Recovery CO2-EOR
Authors: Sheikh Fathesha
Published: December 2021

As fossil fuels will continue to be a key source of energy for the world, the role of carbon capture utilization and storage (CCUS) has become increasingly important in addressing climate change by limiting emissions and by establishing a pathway to reaching net-zero. In spite of its significance, the deployment of CCUS globally in the past decade has not met expectations. It is largely due to the challenges in commercializing the technology. On the contrary, ADNOC successfully deployed CCUS in 2016 and has been operating Al Reyadah - the world's first CCUS project in Iron & Steel Industry and Middle East's first commercial CCUS project for enhanced oil recovery (CO2-EOR).

Similar to other industrialized economies, Abu Dhabi has various sources where carbon dioxide (CO2) is emitted. It also has an advanced oil & gas industry which requires CO2 for enhanced oil recovery (EOR) in order to improve production output. ADNOC synergized these two industries to create a business case. The concept of a CO2 network, linking CO2 producer (source) and CO2 user for EOR (sinks) was developed as far back as 2008. Various studies where undertaken and a steel facility was identified as an ideal choice for a 1st project, given availability of CO2 and proximity to the ADNOC oil fields. In 2012, Al Reyadah was formed to develop the facility and pipeline that is operating today. This is the first step in a vision that would see multiple sources within Abu Dhabi that will be connected via a pipeline network to supply the CO2 needs of ADNOC for EOR, sequestering CO2 and reducing the UAEs greenhouse footprint, whilst freeing up vital hydrocarbon gases (used currently in EOR) for use in commercial industry.

From inception, Al Reyadah has been referenced for decarbonization by many global organizations including International Energy Agency (IEA) and International Renewable Energy Agency (IRENA) and has won prestigious recognitions from Carbon Sequestration Leadership Forum (CSLF) and Emirates Energy Awards (EEA).

This paper discusses the various strategies and commercialization tactics that ADNOC applied to deploy this unique project, which is only among 21 CCS/CCUS projects operating in the world in 2020 and a precursor to thousands of CCS/CCUS projects that are expected to be built globally in the coming years.
Understanding the Impact of Brine Hardness on Chemical Enhanced Oil Recovery Surfactants Performance: A Data Journey
Authors: Company Roberto , Hocine Sabrina , Pousset Baptiste , Morvan Mikel
Published: December 2021

Brine composition is one of the key parameters in the design of a surfactant based oil recovery process and is a condition imposed by the reservoir nature. This brine can contain a large variety of ions including monovalent and divalent cations (hardness), which impacts the surfactants solubility. Moreover, hardness evolution during the injection process can also impair surfactant formulations’ performances. Water treatment processes are useful ways to mitigate such risks, but they imply higher CAPEX for the process. As a consequence, the selection of the right surfactant will have a large impact on the cost and on crude oil production. This paper describes solution properties of the most common surfactants used in surfactant flooding i.e. Alkyl Benzene Sulfonates (ABS) and Internal Olefin Sulfonates (IOS) as a function of the brine hardness and will be compared with Internal Ketone Sulfonates (IKS), a new bio-based surfactant family.
New Insights on the Lower Lekhwair Formation offshore Abu Dhabi: Understanding the Key Role of Lithocodium/bacinella Floatstones on Large Scale Reservoir Quality Variations
Authors: Tendil Anthony J.-B. , Galluccio Laura , Breislin Catherine , Alsabeai Jawaher A. , Lavenu Arthur P. C. , Obara Hidenori
Published: December 2021

The Lower Cretaceous Lekhwair Formation is one of the most prolific oil reservoirs in onshore and offshore UAE, yet the available literature on this interval remains limited. Based on a recent study carried out in collaboration with ADNOC Offshore, the present paper provides new insights into the comprehension of the interplay between primary depositional and secondary diagenetic controls on the reservoir performance, which is of crucial importance for the refinement of the static and dynamic models.

In offshore Abu Dhabi, the Lower Lekhwair Formation is characterised by an alternation of relatively thick argillaceous (dense zones) and clean limestones (reservoir zones). Reservoir zones consist of basal, low to moderate energy inner ramp deposits, grading upward into thick inner and mid-ramp sediments. Lithocodium/Bacinella is the volumetrically dominant skeletal allochem and can form m-thick, stacked floatstone units. Such Lithocodium/Bacinella-rich floatstones are interpreted to originate from a mid-ramp depositional setting as a result of an increase in the accommodation space. By contrast, the contribution of Lithocodium/Bacinella floatstones is significantly reduced in inner ramp settings where these tend to form cm- to dm-scale, laterally discontinuous interbeds.

The combination of sedimentological findings with diagenetic data provided an enhanced understanding of the origin and variations of the reservoir quality across the Lower Lekhwair Formation. In more detail, the best reservoir quality occurs within poorly cemented, Lithocodium/Bacinella-rich floatstones with grain-supported matrices, which favoured the preservation of a macropore-dominated pore system allowing an effective fluid flow. By contrast, the mud-supported textures with only rare and localised occurrence of mm- to cm-scale Lithocodium/Bacinella clumps, present the poorest reservoir quality due to the isolated nature of the macropores and the relatively tight micrite matrix surrounding them. At the large scale, the Lower Lekhwair shows an upward increase in reservoir quality, consistently with the upward increase in abundance and thickness of the Lithocodium/Bacinella-rich floatstones.

The integration of depositional features with diagenetic overprint in the Lower Lekhwair Formation shows the fundamental role played by Lithocodium/Bacinella-rich floatstones with grain-supported matrices on the reservoir quality distribution. The impact of the Lithocodium/Bacinella floatstone matrices on the reservoir performance was never investigated before and hence represents an element of innovation and a powerful tool to predict the distribution of the areas hosting the best reservoir properties.
Capex-Free Production Facilities Optimization Opportunities by Exploiting Installed Automation Infrastructure and Unused Functionalities
Authors: De Sousa Drumond Jose David
Published: December 2021

Operational Excellence and Automation Excellence go hand in hand when it comes to enabling process optimization and cost-reduction opportunities in Upstream Oil & Gas Operations.

As part of our Digital Journey in the Upstream Business, multiple streams and workflows have been created to successfully identify and explore the use of new technologies to foster collaboration, achieve higher levels of efficiency, lower operating costs, maximize production and asset integrity, improve decision making, and lower the carbon footprint of all of our exploration and production activities.

While our Digital Journey has been highly successful in identifying, assessing and implementing new technologies and novel solutions, it has also made very clear, during the development of business-cases’, that a rather big number of existing and older facilities were not going to be good cost-effective candidates for the deployment of many of the identified solutions and technologies. As an established and rooted operator with a large number of aging facilities, these presented an additional challenge to dig deeper and look further for solutions to cover all of these remaining assets, no matter how old or small they could be.
Novel Sandstone Stimulation Using Thermochemical Fluid: Successful Field Application
Authors: Hassan Amjed Mohammed , Al-Nakhli Ayman Raja , Mahmoud Mohamed Ahmed
Published: December 2021

Sandstone acidizing is implemented to remove the damage from the near-wellbore region. Different techniques are used to remove the formation and damage and improve reservoir productivity. This paper presents a novel sandstone stimulation technique using thermochemical fluids. The used chemicals are not reactive at surface conditions and react only at the downhole conditions. The reservoir temperature or pH controller can be used to activate the chemical reaction. A successful field application of the proposed method is reported in this paper.

Different measurements were conducted to assess the performance of the new technique. A compatibility study was conducted at different conditions to evaluate the generation of acid foam. Also, Coreflood experiments were performed by injecting the foam generating solutions into tight sandstone cores. The rock permeability and the pores network were evaluated before and after the chemical injection. Scanning electron microscopy (SEM) and nuclear magnetic resonance (NMR) and analyses were performed. Moreover, a field application of the in situ acid foam generation was conducted. The treatment was implemented by injecting the solutions to react at the downhole conditions and improve the well injectivity. The profiles of injection rate, circulation pressure, and total volume were monitored during the field treatment to assess the treatment performance.

Results showed that the used solutions can generate foam in less time and the volume of the generated foam is around 30 folds of the original chemical volumes. The in situ generated foam can penetrate deeper in the reservoir due to the larger foam volume compared to original chemicals, leading to improve treatment efficiency. Also, the new technique increased the rock permeability from 0.6 to 420 mD due to the dissolution and removal of illite minerals as well as the generation of micro-fractures due to the pressure pulses. The field application showed a very successful performance and the well injectivity was increased by 18 times after the treatment.

The proposed technique utilizes thermochemical fluids to generate acid foam at the reservoir conditions. This technique can eliminate all the risks associated with HSE concerns, in addition to the corrosion issues. Also, the proposed treatment showed a successful field application and increased the well injectivity up by 18 folds of the original injectivity.
Mangrove Restoration and Conservation as a Carbon Offset Option: A Case Study in the Niger Delta Region
Authors: Calderucio Duque Estrada Gustavo , Sali Jason , Piras Patrizio , Jallais Norbert , Amaechi Uchechukwu , Bedford-Fubara John , Pedroni Paola Maria
Published: December 2021

Despite their limited global distribution, mangroves have gained attention as a potential carbon offset option due to their high carbon storage capacity and diverse social and environmental co-benefits. Carbon stock in mangroves (global average=2,790tCO2eq/ha) is about four times higher than in terrestrial forests and contributes to almost 10% (37GtCO2eq) of global terrestrial carbon pool. Mangrove carbon sequestration averages 6.9tCO2eq/ha/yr but may reach more than 20tCO2eq/ha/yr. Literature suggests that over 812,000ha of mangrove areas, spread over 106 countries/territories, show potential for restoration. Furthermore, globally, mangroves have been lost at a rate of 1-2%/yr, which may account for an annual emission of about 0.09-0.45 GtCO2eq/yr that can be potentially avoided through conservation actions.

Mangroves within the Niger Delta Region (NDR) cover 800,000ha (6% of world extent), and contain an estimated carbon stock of 2.2GtCO2eq. In 2017, Eni's subsidiary Nigerian Agip Oil Company (NAOC) launched a voluntary initiative to restore mangroves to promote social and biodiversity benefits while also contributing to offsetting its GHG emissions. A 30-ha pilot restoration area was identified in Okoroma, Bayelsa, where mangroves had failed to naturally recover from oil spills caused by third party interference in 2014. Site assessments were carried out in 2018 and indicated residual soil contamination (hydrocarbons/metals) and low fertility, a typical characteristic of soils in the NDR.

A restoration trial (n=90 seedlings) using nursery-reared seedlings resulted in 100% survivorship and high growth rates, confirming the feasibility of active restoration across the entire site. Although soil contamination was lower than when the spills occurred, we concluded that the combination of residual contamination, low soil fertility and site topography had restricted the natural regeneration process. This in turn risked further soil degradation and ultimately erosion and permanent habitat loss. To prevent this from happening, a long-term restoration program based on the transplantation of fertilized seedlings in partnership with local communities is proposed.

In addition to the benefits to the local communities and the environmental restoration, this project is expected to allow for the sequestration of 2,970tCO2eq in 20 years and avoid the emission of an estimated 60,000tCO2eq from soil carbon, numbers that could be scaled up in the future to a much larger area. The results of this case study further confirm the possibility of using mangroves as a Natural Climate Solution to offset GHG emissions from O&G operations.
Engineered Composite Lost Circulation Solution to Successfully Cure Total Losses During Drilling Across Naturally Fractured Formations in Ghawar Gas Field, Saudi Arabia
Authors: Siddiqi Faizan Ahmed , Caballero Carlos Arturo Banos , Moretti Fabricio , AlMahroos Mohamed , Aswal Uttam , Atriby Kamal
Published: December 2021

Lost circulation is one of the major challenges while drilling oil and gas wells across the world. It not only results in nonproductive time and additional costs, but also poses well control risk while drilling and can be detrimental to zonal isolation after the cementing operation. In Ghawar Gas field of Saudi Arabia, lost circulation across some naturally fractured formations is a key risk as it results in immediate drilling problems such as well control, formation pack-off and stuck pipe. In addition, it can lead to poor isolation of hydrocarbon-bearing zones that can result in sustained casing pressure over the life cycle of the well.

A decision flowchart has been developed to combat losses across these natural fractures while drilling, but there is no single solution that has a high success rate in curing the losses and regaining returns. Multiple conventional lost circulation material pills, conventional cement plugs, diesel-oil-bentonite-cement slurries, gravel packs, and reactive pills have been tried on different wells, but the probability of curing the losses is quite low. The success with these methods has been sporadic and shown poor repeatability, so the need of an engineered approach to mitigate losses is imperative. An engineered composite lost-circulation solution was designed and pumped to regain the returns successfully after total losses across two different formations on a gas well in Ghawar field.

Multiple types of lost-circulation material were tried on this well; however, all was lost to the naturally fractured carbonate formation. Therefore, a lost-circulation solution was proposed that included a fiber-based lost-circulation control (FBLC) pill, composed of a viscosifier, optimized solid package and engineered fiber system, followed by a thixotropic cement slurry. The approach was to pump these fluids in a fluid train so the FBLC pill formed a barrier at the face of the formation while the thixotropic cement slurry formed a rapid gel and quickly set after the placement to minimize the risk of losing all the fluids to the formation. Once this solution was executed, it helped to regain fluid returns successfully across one of the naturally fractured zones. Later, total losses were encountered again across a deeper loss zone that were also cured using this novel approach.

The implementation of this lost-circulation system on two occasions in different formations has proven its applicability in different conditions and can be developed into a standard engineered approach for curing losses. It has greatly helped to build confidence with the client, as it contributed towards minimizing non-productive time, mitigated the risk of well control, and assisted in avoiding any remedial cementing operations that may have developed due to poor zonal isolation across certain critical flow zones.
Innovative Reverse Engineering Approach in Design and Construction of New Gas Processing Facility in Brown Field Block Through Optimum Utilization of Excess Materials and Idle Equipment to Improve Capital Stewardship and Inventory Management. Case Study: Field X Associated Gas Recovery Project
Authors: Yudhy Muhammad Riandhy Anindika
Published: December 2021

Successful project management boils down to effectively and efficiently managing resources to meet the project's cost and schedule. The ability to manage project effectively becomes increasingly important to recover capital project expenditures in expiring Production Sharing Contracts (PSC) blocks. The longer the time needed for a project to complete, the higher the project capital and the lower the capital recovery. Referring to look back result of several major capital facility projects, the key challenge in meeting the project cost and schedule is related to procurement of long lead materials and key process equipment. In brown field blocks, there is an opportunity to perform reverse engineering by optimally utilizing the excess materials in the warehouse and idle/unused process equipment to solve the key challenges. As additional benefit, utilization of excess materials and idle process equipment will improve inventory management and capital stewardship, since the cost to relocate and modify the equipment are significantly lower than the cost of buying a new equipment.

Field X Associated Gas Recovery Project (AGRP) provided an excellent case study of successful reverse engineering approach using excess material and idle equipment in design and construction of a new gas processing facility in brown field block. Field X AGRP is designed to recover and process associated gas from X field to be used as fuel gas for the gas turbines at the internal Power Generation Plant. However, based on lesson learned from similar opportunity in the past, the cost of construction and installation of a new gas processing facility using new construction materials and new process equipment is very high, which is uneconomic at the current oil price environment. Therefore, to make the project economic, the project team shall consider the utilization of available excess material in the warehouse and idle/unused equipment into design basis. Project team conducted assessment to several facilities across the concession area to gather equipment specification data of idle process equipment and the size of available excess materials. The gas processing facility design was reverse engineered to optimally utilize the idle process equipment and excess materials.

The utilization of idle equipment and excess material in construction of the gas processing facility has successfully generated cost saving up to 5 times the project cost from avoiding purchase of new equipment and new construction materials. The project successfully recovered associated gas at the rate of 0.5 MMSCFD to be used as fuel to gas turbine and produced 60 BOPD condensate from gas-liquid separation process
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

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

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

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

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

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

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

The 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

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.
Successful Implementation of Polymer Flood in Aishwariya Field, Rajasthan, India - Concept to Full Field
Authors: Singh Aditya Kumar , Vegesna Pruthvi Raju , Prasad Dhruva , Kachodi Saideep Chandrashekar , Lohiya Sumit , Srivastava Deeksha , Raj Rahul , Koduru Nitish , Mishra Sudhakar , Barua Debaditya , Pandey Amitabh
Published: December 2021

The Aishwariya Oil Field located in Barmer Basin of Rajasthan India having STOIIP of ∼300 MMBBLS was initially developed with down-dip edge water injection. The main reservoir unit, Fatehgarh Formation, has excellent reservoir characteristics with porosities of 20-30% and permeability of 1 to 5 Darcys. The Fatehgarh Formation is subdivided into Lower Fatehgarh (LF) and Upper Fatehgarh (UF) Formations, of which LF sands are more homogenous and have slightly better reservoir properties. The oil has in-situ viscosity of 10-30 cP. Given its adverse waterflood mobility ratio, the importance of EOR was recognised very early. Initial screening studies identified that chemical EOR (polymer and ASP) was preferred choice of EOR process. Extensive lab studies and simulation work was conducted to develop the polymer flood concept. A polymer flood development plan was prepared targeting the LF sands of the field utilizing the lessons learnt from nearby Mangala Field polymer implementation project.

The polymer flood in Aishwariya Field was implemented in two stages. In the first stage, a polymer injectivity test was conducted in 3 wells to establish the potential for polymer injection in these wells. The injection was extended to 3 more wells and continued for ∼4 years. Significant water cut drop was observed in nearby wells during this phase of polymer injection. In the next stage, polymer flooding was extended to the entire LF sands with drilling of 14 new infill wells and conversion of 8 existing wells to polymer injectors. A ∼14 km long pipeline was laid from the Mangala Central Polymer Facility to well pads in the field to cater to the requirement of 6-8 KBPD of ∼15000 ppm polymer mother solution. The philosophy of pre-production for extended periods was considered prior to start of polymer injection for all wells as it significantly improved injection (reduced skin) and conformance.

Full field polymer flood project was implemented, and injection was ramped up to the planned 40-50 KBPD of polymerized water within a month owing to good injectivity and polymer solution quality. A detailed laboratory, well and reservoir surveillance program has been implemented and the desired wellhead viscosity of 25-30 cP has been achieved.

Initial response shows significant increase in oil production rate and decrease in water-cut. This paper presents the polymer laboratory studies, initial long term injectivity test results, polymer flood development concept and planning, simulation studies and field implementation in LF Formation in Aishwariya Field.
Offshore Health Innovations
Authors: Logunov Konstantin Valerievich , Antipov Sergei Anatolievich , Karpov Andrey Borisovich
Published: December 2021

Objectives/Scope

Analysis of 15 years results of remote occupational health care in oil and gas production industries.

Methods, Procedures, Process

Continuous observation, statistical analysis of morbidity, mortality, and treatment results in industrial personnel at different endpoints depending on the variability of care models. Cost-efficacy analysis of several occupational health interventions. Targeted polls of Customers. Dynamics of new Customers.

Results, Observations, Conclusions

The best practices which provide the maximum efficacy include risk assessment and risk management, action planning for emergencies, telemedicine, education, registry maintenance. Each of all these gave a 10-100-fold rise in Customer satisfaction, seriously improved medical statistics. Telemedicine implies both: the delivery of highly specialized diagnostic technologies directly to the industrial production site, where a GP or paramedic is present, and it implements the direct replacement of medics with gadgets at the patient's bedside. Education involves hands-on training for both industrial personnel at remote sites and for medical professionals who provide care. The 2020-21 COVID19 pandemic was a great real stress test for remote health models when systemic integrated management procedures played a pivotal role in ensuring smooth industry operation due to the high quality of back medical services.

Novel/Additive Information

Modern efficient models of medical care for remote industries are necessarily comprehensive, modular, adaptive, and rely on personnel health registers. Remote health practices gain a 5-15% rise in price every year, but it pays off in greater labor productivity and in improving the health of industry personnel.