bluuebunny/crossref_metadata_2025_split huggingface dataset:
Joint Optimization of Oil Recovery and Carbon Intensity in a Middle-East Oil Field Under Miscible Water Alternating Gas
Authors: Blanchet M. , Bourgeois M. , Guérin S. , Garnier O. , Chehade P. , D’Alessandro S. , Prinet C. , Marmier R. , Barres-Montel V. , Alhosani A. K. , Alhammadi S. 
Published: October 2023

Abstract
This work investigates how the green-house gas (GHG) emissions of a producing oil field can be reduced through adaptation of the reservoir management, i.e. the injection and production guidelines. Indeed, the world’s energy production must be decarbonized as far as possible, and this includes minimization of the emissions associated to the oil and gas extraction itself. An additional decision criterion for oil and gas projects is the hydrocarbon carbon intensity, which is the emissions total divided by the production total, expressed in kgCO2eq/boe. The reservoir management strategies now attempt the joint optimization of all the following dimensions: net present value, short-term production, final recovery, and now oil carbon intensity. In some WAG fields, several controls are available even after the development is finalized: flow rates of both gas and water in each injector, duration of injection of each phase, possible conversion from WAG to water injection. A method has been devised to perform the joint optimization: a reservoir simulator is coupled with a surface model containing GHG emissions equations for compressors, pumps, turbines according to their throughputs. In brown fields, this emissions model can be calibrated on historical profiles and energy consumption per machine, while in green fields, a synthetical model can be built from theoretical operating curves and calibrated a posteriori. In this work, the method was applied on a giant Middle-East carbonate oil field under Miscible WAG injection. Numerous reservoir management scenarios were run, resulting in new production and injection profiles, together with their associated GHG emissions profiles, without the need for time-consuming loops between subsurface and development or exploitation teams. All scenarios were ranked in recovery and carbon intensity simultaneously. For the selected field, it was found that reservoir management actions can be strong levers to reduce the carbon intensity of the produced oil, where required – typically by 10% or more. The most efficient reservoir management actions for GHG reduction were those that reduce the gas injection rate and therefore the associated gas compression requirements. The actions did not impact the short- and mid-term oil production but lead to a reduction of one point of ultimate recovery. Reservoir management decisions must consequently be compromises between ultimate recovery, carbon intensity and net present value. The integrated production and emissions prediction tool proves extremely helpful to identify the relevant reservoir management scenarios, perform informed arbitration or enforce hard-fixed carbon intensity constraints.
Preventing Process Safety Incidents in Upstream & Downstream Oil & Gas Operations by a Systematic Approach to Strengthen Process Safety & Asset Integrity Barriers
Authors: Tayab Muhammad , Suwaidi Hamda Al , Zaabi Hind Al , Kumar Pravin , Shah Vishal , Saif Abdulla 
Published: October 2023

Abstract
By prioritizing process safety and asset integrity, ADNOC has established a strong safety culture and a track record of safe and reliable operations. Its commitment to safety has helped to prevent incidents and protect its personnel, the environment, and its assets. Process safety incidents in the oil and gas industry can have serious consequences, including injury or loss of life, environmental damage, and damage to assets. Such incidents can occur during exploration, production, transportation, and refining of oil and gas. Some common process safety incidents in the oil and gas industry include: Blowouts: Blowouts occur when there is an uncontrolled release of oil or gas from a well. They can be caused by a number of factors, including equipment failure, human error, and natural disasters.Fires and explosions: Fires and explosions can occur due to a variety of reasons, including equipment failure, leaks, and human error. These incidents can cause significant damage to assets, as well as injury or loss of life.Chemical releases: Chemical releases can occur during the handling and processing of hazardous materials, such as hydrocarbons and chemicals used in production processes. These incidents can result in environmental damage, as well as injury or loss of life.Structural failures: Structural failures can occur due to equipment failure, natural disasters, or inadequate maintenance. These incidents can cause damage to equipment and facilities, as well as injury or loss of life.
An analysis of over 50 Process Safety Events (PSE) involving Loss of Primary Containment (LoPC), both from Upstream & Downstream segments of Oil & gas operations was performed. The causes of these events were mapped with elements of process safety and asset integrity framework to identify focus areas.
Preventing process safety incidents in the oil and gas industry requires a comprehensive approach that includes identifying and assessing risks, implementing preventive measures, establishing barriers, monitoring and maintaining barriers, and training personnel. Companies must also comply with relevant regulations and standards, and continuously improve their safety systems and procedures to ensure that risks are minimized and incidents are prevented. The results indicated that deficiencies and inadequacies in risk identification contributed to majority of process safety events.
To prevent process safety incidents, companies like ADNOC must implement a comprehensive process safety management system that focuses more on risk assessments, and safety training. In addition, companies must prioritize asset integrity management to prevent equipment failures and maintenance issues that can lead to process safety incidents.
Energy Efficiency Surveillance Tool (EEST)
Authors: Al Farsi H. I. , Wahaibi A. , Subhi N. , Maqbali A. , Brockman A. , Rumhi J. , Sabri A. , Abri S. , Shuaily I. , Al Hosni H. , Al Harthi A. , Al Araimi M. , Subhi A. , Willcox P. , Balushi A. , Rashdi M. , Riyami A. , Ghammari R. 
Published: October 2023

Abstract
The oil and gas industry, which is the most energy-intensive of all industrial processes, has a huge potential for efficiency improvements. EEST is an engineering tool embedded in Nibras (PDO's Real Time Operation Portal) to:
Highlight ‘Energy Gaps’ (i.e. where energy consumption is higher than target) Enable proactive identification and implementation of opportunities to save energy, cost and emissions.
This project scope is to deploy EEST across PDO (~650 equipment in 20 assets).
EEST provides a lean dashboard to ‘follow the money’ on energy. It aims to continuously reduce energy consumption and GHG emissions through review and adjustment of energy performance against equipment and system-based targets by human interventions. EEST has been linked to the Exception Based Surveillance (EBS) tool and process where alerts are triggered based on energy gaps and sent to the action owner to proactively close the gaps.
EEST has been implemented without any additional hardware or software cost. It is implemented in PDO's real time operation portal, which is used extensively for WRFM surveillance and process monitoring. It uses standard thermodynamic principles behind all energy gap calculations.
Caprock Porosity and Permeability Characterisation for CO2 Storage Seal Integrity Assessment Using Preserved Core and Drill Cuttings
Authors: Sazali Wan Muhammad Luqman , Buckman Jim , Jingsheng Ma , Yong Wen Pin , Busch Andreas 
Published: October 2023

Abstract
Carbon capture and storage (CCS) requires sealing caprocks to ensure the stored CO2 is contained in the reservoir and not leaking towards the surface. Many caprocks are composed of mudrocks, a siliciclastic sedimentary rock with a high clay content. We here analyse such a caprock from the Field S which is a potential CO2 storage site in the Sarawak Basin, East Malaysia. The determination of important caprock properties, like porosity and permeability, is often difficult and requires fresh core material that is adequately stored for lab testing. When such core material is not available, drill cuttings might be used as alternatives to predict formation properties if suitable empirical relationships are available which is the objective of this study. Therefore, we performed a petrophysical characterisation of core and cutting samples using mercury intrusion porosimetry, unsteady state pulse decay permeameter, nuclear magnetic resonance and helium pycnometer measurements. Only MIP and helium pycnometer are suitable to determine porosity and permeability on drill cuttings, while plug samples can be used for permeability tests under subsurface stress conditions. The lab data has then been correlated with well log data to further understand the porosity and permeability trend for prediction purposes. The caprock in Field S is divided into two facies (Seal A and Seal B) with varying clay contents of ~20 and ~40% respectively. However, laboratory derived porosity and permeability values do not vary significantly between the two facies. This might be because Seal B (higher clay content) is significantly over-pressured compared to Seal A, potentially resulting in porosity preservation during compaction, resulting in increased permeability. This is consistent with the time-to-depth conversion from seismic data, where Seal B is identified as being undercompacted in comparison to Seal A. Here, we will present our workflow in predicting porosity and permeability of caprocks based on a petrophysical and mineralogical database developed for Seal A and B. We will discuss issues with this approach and its potential and highlight the difficulties in determining permeability from confined plug or unconfined cutting samples.
The Path to Sustainable Cementing: Embracing a Non-Portland Cement Solution for Oil and Gas Wells
Authors: Abdelaal Ahmed , Elkatatny Salaheldin , Fattah Ahmed Abd El 
Published: October 2023

Abstract
Geopolymer cement shows great promise as an alternative to Ordinary Portland cement (OPC) in the oil and gas industry due to OPC's environmental concerns and high energy consumption during manufacturing. While geopolymer cement is already widely used in the construction sector, its full-scale application in the petroleum industry is yet to be realized. One critical area where geopolymer cement can play a significant role is in high-pressure well cementing applications. To replace heavy-weight Portland cement slurries in these applications, the development of high-density geopolymer cement becomes essential. However, there is a challenge associated with high-density cement slurries that use dense materials as weighting agents. This challenge is known as sedimentation, which leads to issues like heterogeneity and density variation along the cemented sections. Overcoming this problem is crucial for ensuring the effective and reliable use of high-density geopolymer cement in the oil and gas industry. The target of this work is to introduce a new formulation for heavy weight geopolymer systems and evaluate the use of perlite powder as an anti-sedimentation additive in these systems. The study involved the preparation of Hematite-based Class F fly ash (FFA) geopolymer cement slurries with different concentrations of perlite (0%, 1.5%, and 3% by weight of binder (BWOB)). To assess the sedimentation problem, the API method was used. Various geopolymer properties, such as unconfined compressive strength (UCS), elastic properties, and rheological properties, were examined in relation to the effects of perlite. The results indicated that the inclusion of perlite in high-density hematite-based FFA geopolymer led to a significant reduction in the sedimentation issue. This improvement was achieved by increasing the yield point and gel strength of the slurry. Moreover, the UCS showed an increase with increasing the percentage of perlite. The evaluation of young's moduli (YM) and Poisson's ratios (PR) demonstrated that the developed perlite-based geopolymer systems exhibited greater flexibility compared to Class G cement systems. Based on the findings, it was concluded that the optimal perlite concentration for addressing sedimentation while maintaining desirable mixability and rheological properties was 3% BWOB.
Configurable Adaptive Chemical Inflow Control Device Eliminates Intervention
Authors: Asthana P. , Sulaiman A. , Jacob S. , Bukhamseen A. 
Published: October 2023

Abstract
The successful application of Passive and Autonomous Inflow Control Devices (ICDs) to delay water breakthrough, extend well life and increase recovery in Horizontal wells is one of the major technical achievements in the oil and gas industry in recent years. These devices are used as open hole completion equipment to balance inflow along the well borehole section and have enhanced well performance in an efficient and cost-effective manner.
To understand the history and background of the field challenge and previously proposed solutions, the paper presents comprehensive and chronological evolution of ICD's through time. This timeline starts with the introduction of conventional ICDs evolving to adaptive ICDs, and presenting the way forward for the technology. This paper introduces a new Chemistry based Autonomous Inflow Control Device (Chemical-AICD or C-AICD) for oil wells which restricts water based on chemically induced alterations on fluid path. The operation of these devices is completely independent of viscosity and density and need no intervention for water shutoff. The design allows for injection activities even after the device is closed.
The operational of the device incorporates a time trigger selective water/oil dissolvable mechanism on thin coatings applied on a ball. The time and environment dependent selective dissolution changes the diametrical position of the ball within a specially designed funnel, changing the flow port area available for inflow. While newer, advanced completion technology is created to enhance well performance, it is often more complex in design and field installation and comes at a higher cost than existing field-proven technologies. The revolutionary Chemical-AICD design allows applications for oil production in fields where minimization of water production is desirable, while being both cost effective and efficient. A wide range of applications for interventionless water shutoff are presented with a comparison between various ICDs for a typical application to showcase the unique technical and economic benefits of a Chemical-AICD.
Challenges and Lessons Learned: Rotating Packed Bed (RPB) Technology for Acid Gas Removal
Authors: Rahman F. H. , Salihuddin R. S. , Yiin T. K. , Surmi A. , Zuhdi M. F. A. 
Published: October 2023

Abstract
Natural gas produced from many major reservoirs can contain high amounts of carbon dioxide (CO2) and must be treated to meet typical specifications for pipelines or liquefaction plant feed (Hassan et. al 2018). These treatment processes often require high-pressure operations forming highly concentrated CO2-rich streams. There are many factors that can be stumbling block for the development of such a field with high contaminants of CO2.
World high CO2 gas field distribution is shown in Figure 1 (Burgers et al. 2011), some of the fields are stranded due to high CO2 content and not economically attractive to develop due to current oil price. Hydrocarbon resources with high CO2 content from 15 to 80% mol most of the fields are in south-east Asia, northern Africa, Europe, Brazil, Australia and USA, these fields are still undeveloped or under-develop. There is a need for "game changing" technology to overcome this barrier. It is not as simple as developing other green fields, the challenge is more on separation technology and heat integration, to meet project economics. Not only that, CCUS (Carbon Capture Utilization and Storage) is also a challenge whereby the produced CO2 from reservoir needs to be store back to geological storage or to convert it into other useful products (Hassan et. al 2018).
Comprehensive Screening of Available Technologies to Improve Productivity of Complex Undeveloped Carbonate Reservoir for Optimizing Field Development Plan Abu Dhabi UAE
Authors: Sanchez E. , Moreno B. , Dantla V. , Safaa J. , Jamal Haj Bin Naqeh S , Kadeeb M. 
Published: October 2023

Abstract
"M" is an undeveloped thin and tight carbonate reservoir consisting of four porous bodies isolated by the presence of intra-dense layers. The prominent layer is four feet of thickness. Applying conventional acid stimulation in "M" has been ineffective to increase wells productivity and sustainability. Therefore, the objective is to evaluate different technologies to optimize wells design and improve productivity, overcoming the reservoir challenges with cost efficiency for full-field implementation.
It took the outcome of integrated reservoir analysis for helping in the selection of the best technology based on the results and lessons learnt, that had been applied in different development reservoirs, chasing analogy and comparing similarities in rock-fluid properties such as: composition, architecture, porosity, permeability, water saturation, and PVT, from core, logs, and production test analysis. Thus, induced hydrofracking, fishbone, abrasive jetting and limited entry liner were screened for feasibility. Once the technology qualified, the economic analysis and detailed design was established for planning purpose to be implemented in the first horizontal producer in "M" reservoir.
A horizontal well was drilled in a sheet-like carbonate reservoir (pancake stratigraphy) with the advantage of having geosteering technology. It vanquished the structural complexities and the well remained in contact with the reservoir 3500 ft out of 4000 ft in four ft of thickness, nevertheless, two anomalies such as detected shear zones while drilling tried to put the well outside the target. The multidisciplinary team and real time analysis made the well always to come back on target without compromising time efficiency. The well was completed as producer with electrical semisubmersible pump as artificial lift method.
According to the feasibility and screening of the technologies, abrasive jetting resulted in the most effective technique, for production enhancement as cost-effective alternative to induce hydrofracking and other applications in "M" reservoir as a trial. Abrasive Jetting is conducted with 28% HCL, and the distance between stages is designed ~ 20 - 30 ft. to create the channels for maximum production. The expected average wormhole and skin reduction are 1.3 ft and 2.3 respectively. The production testing will be executed to evaluate the well performance, pre and post abrasive jetting job.
Based on the successful application of abrasive jetting technology in the first horizontal producer well in "M" reservoir, the technology will be deployed in the marginal reservoir for full field development plan.
Physics Informed Machine Learning Models for Simulating CO2 Injection into Saline Aquifer
Authors: Sheth S. M. , Shaykhattarov M. , Dias D. , Sathujoda S. T. , Coker O. 
Published: October 2023

Abstract
The injection of carbon dioxide (CO2) into saline aquifers is an important strategy for mitigating greenhouse gas emissions. However, accurately simulating this complex process is computationally expensive, requiring numerical models handling the underlying physics of the system ranging from thermal effects to geochemistry. In recent years, Physics Informed Machine Learning (PIML) models have emerged as promising complimentary tools to physical simulators, leveraging the power of machine learning while incorporating prior knowledge of the physical system.
In this work, we present a PIML model for simulating CO2 injection into saline aquifers. This model is based on an auto-encoder formulation that compresses the state image, that is pressure and saturation distributions and trains a fully connected neural network that can predicts the evolution of the variables in time. The model consists of an encoder that performs the said compression, a transition layer which takes in the well controls and injection rates as inputs, and the decoder that projects the solution from the null space to the original physical space.
The training dataset which includes spatial and temporal data for a limited ensemble of reservoir models with varied well controls is generated using a full fidelity physical simulator which performs reactive-transport calculations and models CO2 injection into a saline aquifer. A deep network is trained using TensorFlow and physical loss functions are augmented along with traditional reconstruction losses. The training of large field models is done using a domain decomposition- based algorithm that breaks up the physical domain into smaller sub-domains and the resulting training is about an order of magnitude faster than traditional full field algorithms. Once the training is performed, the model is deployed on a much larger ensemble with validation of random realizations using the physical simulator.
We present results on a heterogenous three-dimensional subsurface model and highlight the potential benefits of PIML models, including reduced computational costs, improved accuracy, and increased flexibility. The resulting inference workflow is several folds faster than running traditional full fidelity simulators on an ensemble of realizations. Additional results are presented on cases with deformed geometry and complex structural elements such as faults and pinch out cells.