bluuebunny/crossref_metadata_2025_split huggingface dataset:
Strategies for Prevention of Downhole Tool Failure Caused by High Bottomhole Temperature in Geothermal and High-Pressure/High-Temperature Oil and Gas Wells
Authors: Khaled Mohamed Shafik , Wang Ningyu , Ashok Pradeepkumar , Chen Dongmei , van Oort Eric 
Published: March 2023

Summary
High bottomhole temperature can lead to decreased downhole tool life in geothermal and high-pressure/high-temperature (HPHT) oil and gas wells. The temperature increase is exacerbated when circulation stops (e.g., during connection, tripping, and well control situations). While continuous circulation technology is an appropriate solution for managing temperature, it is not yet widely adopted in HPHT and geothermal drilling practices. This work investigates factors that impact downhole temperature (DHT) and recommends strategies to better manage the temperature when continuous circulation is not available.
An integrated thermo-hydraulic model was developed to capture the transient behavior of DHT and was applied here to study the transient temperature profile when there is no fluid circulation. The model was validated using the open-source FORGE field data set, with the mean absolute percentage error between 1% and 4%. In addition, hundreds of case scenarios were numerically studied to investigate the impact of several key factors on the DHT.
The evaluated factors include the pumps-off time, type and physical properties of the drilling fluid, wellbore hydraulic diameter, reservoir temperature, geothermal gradient, total wellbore depth and profile, and operational parameters before stopping the circulation. The cooling effects of different drilling parameters were compared to a benchmark case of continuous circulation. A correlation map was generated to visualize the impact of those parameters on the DHT distribution when circulation stops. A logarithmic relationship between the pump stop time and the DHT was observed. For the FORGE case scenario, the DHT increases by 27°C and 48°C after the pump stops for 30 minutes and 60 minutes, respectively. It was observed that water-based mud (WBM) with a high viscosity increases fluid convection heat resistance between the formation and wellbore. Also, drilling with a higher flow rate before stopping the pump can cool the near-wellbore formation faster and reduce the DHT even after circulation ceases. Wells with high geothermal gradients, like FORGE wells, have a higher temperature buildup during circulation stoppage than wells with low geothermal gradients targeting the same reservoir (formation) in-situ temperature.
This study investigates the efficacy of different cooling strategies to avoid DHT buildup when there is no circulation. It thereby facilitates the optimization of geothermal and HPHT well design and construction to prevent downhole tool failures. The developed correlation map can aid drilling engineers in understanding the impact of different drilling conditions on the DHT.
Data Analytics Drives Production Optimization for Gas Lift Wells to the Peak, Case Study from Gulf of Suez.
Authors: Koriesh Mahmoud , El Sheikh Mahmoud , Maher Ahmed , Elwan Mahmoud , El Bohoty Ahmed , Mousa Hisham 
Published: March 2023

AbstractGas Lift has been applied in the oil field for more than 70 years, despite the new technology and developments there is always more optimization that can be done. In this paper we are giving a leading example of one of the oldest gas lift projects in gulf of Suez that has been running for more than 50 years where 540 MMSCFD being pumped on daily basis to produce more than 200 wells as of today. the experience in this field is quite historical but the question is always persisting are we making best use of lift gas volumes and pressure, does every well have the optimum design and receives the optimum gas lift rate. One more important question will be how to prioritize interventions and optimization operations to target wells with highest value.In order to assess the overall gas lift performance of the field an innovative dashboard was created including Key performance indicators that reflect benchmarking of Lift Gas Consumption compared with historical Performance of the field. This should spot the light to the field with lowest efficiency and most probably it is expected higher return of production if we dedicate efforts to this field.Moreover creating wells dashboard has valued new Key Performance indicators with New Diagnostic Graphs that was not given attention by the industry before. Having these diagnostic Plots allowed benchmarking performance of wells for similar reservoir, completion type, gas lift design and sand face completion. Using this technique, it became easy to detect wells with higher potential of production with proper gas lift intervention.Although Analytics can give some guidance on the required actions to enhance production of wells knowing the basic design, having the analytics coupled with Integarated Network modelling and well models added more value to the project.Data Driven Gas Lift Optimization approach was applied since Oct. 2021 in an extensive approach over GOS, the approach succeeded to define more than 74 Optimization and Intervention Opportunities 45 of them were actually intervened in less than a year and added more than 4000 BOPD to production capacity. It was not a surprise that some of historically known underperforming wells were interpreted underperforming for other reasons than gas lift in-efficiency but using Gas lift Analytics re-analysis of the system showed huge value for gas lift intervention in these wells and succeeded to revive them.Data Analytics and Data driven gas lift optimization is proved a huge leap in managing gas lift fields and keeping the system running closer to optimum.
Quantitative Assessment of CO2 Mineral Trapping Capacity in Presence of Sealing Fault in Carbonate Sequences: A Numerical Approach
Authors: Fathy Ahmed , Arif Muhammad , Adila Ahmed Sami , Raza Arshad , Mahmoud Mohamed 
Published: March 2023

AbstractMineral trapping is believed to be the safest and the most secure CO2 sequestration technique where the injected CO2 could be mineralized in the long-term (exceeding 102 - 103 years) geologically within subsurface formations. Nevertheless, the high complexity associated with CO2 mineral trapping capacity predications obscures the in-depth understanding of CO2 mineralization. In this study, a numerical simulation is adopted to demonstrate the impact of carbonate mineralogy in presence of a sealing fault on CO2 mineral trapping capacity.Field-scale CO2 pilot topographic model for three distinct carbonate minerals is simulated to depict the mineral trapping capacity. Thus, realistic petrophysical parameters, reservoir characteristic curves, and other in-situ conditions are upscaled to mimic carbonate formations. Thereafter, the amount of CO2 mineralized is estimated for compositionally distinct reservoirs. Additionally, the effect of injection pressure on CO2 mineralization is assessed upon precipitation/dissolution kinetics calculations. Moreover, the effects of well placement and perforation depth on mineral trapping potential of calcite, dolomite, and siderite dominant reservoirs are assessed.The mineral trapping capacities computed show that increasing injection pressure (base injection pressure to 1.5*base injection pressure) monotonically increased the mineral trapping capacities for calcite and dolomite. However, siderite seems slightly insensitive to the injection pressure increase. This monotonic trend is attributed to enhanced radial displacement and restricted plume migration upward as the injection pressure increases. Moreover, proper CO2 injector placement showed significant enhancement in mineral trapping capacity especially if the injector is near to the fault plane on the leaking side. This study provides in-depth theoretical understanding of the mineralogy effect on CO2 mineralization potential in faulty carbonate sequences. This is driven by the insignificance interest mineral trapping has gained over the years compared to other trapping mechanisms. This is because of the extremely long storage duration needed for mineral trapping to reach its maximum potential. Importantly, the results suggest that CO2 mineralization within carbonate reservoirs immobilize CO2 – thus assisting in stable and long-term permanent storage.
Advanced Lower Completion Technology Applications in Miscible Gas Injection EOR - Unlock Value for Multi Reservoir Onshore Fields
Authors: Xu Siqing , Baslaib Mohamed , BinAmro Ahmed 
Published: March 2023

AbstractMiscible CO2 flood – similar to miscible hydrocarbon gas injection - is a well-established proven EOR development scheme. There have been a large number of CO2 EOR developments worldwide, with deployment in both carbonate and clastic reservoirs. Potential controlling factors on CO2 EOR incremental production and recovery are well understood and widely published. This paper presents an integrated CO2 EOR development study, with emphasis on advanced technologies application – the deployment of advanced lower completion technologies. This paper is a follow up companion paper, presenting additional results, to a previous paper by Xu S. et al (2021). A review is provided concerning successful application of advanced lower completion technologies: namely Maximum Contact Reservoir (MRC) wells, Limited Entry Liner (LEL), and Fishbone drilling. The reservoir geological characteristics from three Onshore Abu Dhabi carbonate reservoirs are presented, and key factors which may lead to poor reservoir sweep are identified. Fine scale 3D compositional models were developed, to simulate reservoir performances when advanced lower completion technologies are deployed. The results show significant injection/production performances compared to conventional horizontal wells development schemes. When under CO2 EOR development, the major recovery mechanisms leading to sweep improvements are highlighted. The deployment of such lower completion technology may prove to be a valuable enabler in a future CO2 EOR development scheme.
ESP Failure Prediction in Water Supply Wells Using Unsupervised Learning
Authors: Reddicharla Nagaraju , Sultan Ali Mayada Ali , Alshehhi Shamma Saeed , Elmansour Ayman , Vanam Prabhaker Reddy 
Published: March 2023

Abstract
Water injection is seen as one of the key field development strategies to achieve the mandated production target as it will maintain reservoir pressure as well as improve sweep efficiency and increase field recovery factor. In current practices water supply wells workovers are planned after Electrical Submersible Pumps (ESP) are failed by adopting run to fail approach. This lead to decrease in well availability and increase in down time which impacts water injection cluster capacity in giant matured onshore oil field.
The objective of this solution is to early detect the failures for ESP wells using Machine Learning (ML), by demonstrating the feasibility of this approach and verifying that the concept has practical potential, the tool can be used to reduce deferment and increase well availability either by extending time-to-failure or better planning and scheduling the workovers. In this solution, Predictive Analytics model was developed based on Algorithms using field sensor data, and well failure history to predict ESP well failure probability. Due to the limited available ESP real time data, it would be a challenge to have an accurate model. The downhole and temperature data is not available in these ESP wells. Hence, we have adopted unsupervised classification approach combined with statistical calculations such as MTBF based on failure history. The solution provides a probability of ESP failures based on the anomalies (anomaly severity) detected from unsupervised machine learning model (individual cluster based), MTBF & number of starts. The probability is normalized based weight-based approach. Additional criteria can be added and considered in the future to fine tune the model and predictions.
The approach has successfully evaluated on 34 water injection clusters in this giant field. The model is able to predict 77% of failures historical failures successfully. The limitations in ESP down-hole data availability and real time quality issues impacted model accuracy. The solution has been successfully deployed in real time mode and able to predict failures 90 to 120 days before failures. This has resulted increase in well availability by 10% and increased water injection system capacity.
This machine learning based approach has been extended to all water injection clusters and also capitalized in other fields to increase well availability and grow capacity with the increasing demand for water injection to sustain and grow production volumes
Geochemical Interactions Among Rock/CO2/Brine Systems: Implications for CO2 Geo-Storage
Authors: Adila Ahmed Sami , Raza Arshad , Zhang Yihuai , Mahmoud Mohamed , Arif Muhammad 
Published: March 2023

AbstractCarbon Capture and Storage (CCS) is one of the promising techniques to mitigate carbon dioxide emissions and move towards net zero targets. The efficiency of a geological storage process is, however, a complex function of CO2/rock/brine interactions. In particular, the effect of geochemical interactions among CO2/rock/brine systems in an aquifer and its associated impact on wetting behavior has not been rigorously investigated before.In this work, we study the effect of the critical parameters affecting the CO2/rock/brine system wettability from a geochemical perspective. In particular, we study the effect of temperature, pressure, and salinity on the wettability of the CO2/calcite/brine system. The wettability was assessed based on the disjoining pressure, which was calculated from calcite surface potential. The geochemical simulator used is based on surface complexation modeling and takes dissolution and precipitations reactions of the minerals and aqueous species into account.The results show that increasing pressure decreases the concentration of calcite surface species &gt;CaOH2+ and &gt;CO3−, while it increases the calcite surface species &gt;CaCO3−. However, increasing temperature increases the concentration of calcite surface species &gt;CaCO3− and &gt;CO3−, while it slightly decreases the calcite surface species &gt;CaOH2+. The results also show higher calcite surface potential and disjoining pressure at higher temperatures and lower salinity, which reflects an increase in water wettability (or a decrease in CO2-wetness) and greater CO2 storage potential in calcite-rich aquifers at these conditions.This paper provides insight into the effect of different influencing parameters on the CO2/rock/brine interactions and CO2/rock/brine wettability, which can help understand the geochemical processes involved in CCS projects under a wide range of operating conditions.
Essential Ingredients of Effective Project Management: A Case Study of Project Execution in the South Pars Mega-Projects
Authors: Daneshkhah Vahid , Younesi Gholamreza , Karbalaee Akbari Meisam , Daneshkhah Hamed 
Published: March 2023

AbstractDuring the past decades hundreds of wells have been constructed in the giant South Pars gas field with different approaches and methodologies leading to diverse outcomes and results. Interestingly enough there have been many operators in the field with distinct performances yet by deploying the same vendors and service providers held in common. By considering that it is statistically proven that the larger the project budget, there are higher chances for failure, effective tailoring of methodologies in large scale mega-projects would be crucial and decisive. In many cases failures are a consequence of simply applying methodologies already experienced in small scale projects on complex and sophisticated projects with a variety of influential factors and a huge network of stakeholders. The study has provided an insight on how effective approaches in project management or conversely mismanagement could play as the main rout cause in a chain of events corresponding to either saved time or Non-Productive Times in well construction operations by presenting real cases elaborated in detail.Cases show how failure in collecting requirements and recognizing the interdependencies among each necessity in the early stages of the project and subsequently overlooking the related cost, time and risks could cause massive cumulative financial loss. Additionally, failure to recognize wise investments in vendors and service providers as the 1-10-100 rule which explains how failure to take notice of one initial investment escalates the financial loss exponentially would have staggering consequences. The current paper explains how being proactive in an extensive planning phase could ease the execution stage as a great investment in time spent. From a human resource perspective, it has been demonstrated that how the ability and skills of the project team e.g. effective communication in complex networks with multiple reporting relationships and data-driven decisions by statistics could prevent cognitive biases and errors in decision making. Furthermore, powerful alignments come from shared and common motivations and morale for all engaged parties and the supply chain being service providers, rig contractors or the field operator and there should be an answer to the question, what's in it for me when asked by each of these parties.Overall the study presents real cases and lessons learned showing how the main rout causes of Non-Productive Times could go back deeply to ineffective project approaches from a project management perspective in a system dynamic chain of events rather than to just address the emerged symptoms of failure in drilling operation.
In Situ Hydrogen Generation Within Gas Reservoirs
Authors: Afanasev Pavel , Popov Evgeny , Cheremisin Alexey , Mikitin Evgeny , Darishchev Viktor 
Published: March 2023

AbstractNowadays, hydrogen is often considered as one of the prospective clean energy carriers. At the same time, the traditional hydrogen production methods also produce significant amounts of greenhouse gases or too expensive to be industrial scaled. In situ hydrogen generation in hydrocarbon-containing reservoirs can be one of the promising ways for low-carbon hydrogen production. However, the conversion of hydrocarbons into hydrogen under the hydrocarbon reservoirs conditions has practically not been studied.This work reports experimental results on the catalytic in situ hydrogen generation from methane under the conditions that can be achieved due to the thermal influence on gas-bearing layers. Hydrogen can be generated within gas reservoirs with non-zero residual oil saturation or in the fields with underlying oil-saturated layers due to the catalytic treatment of the reservoir followed by steam injection and/or in situ combustion. First, the thermodynamic restrictions for the process were determined. Then verification concept experiments were performed in the autoclave setup in static and dynamic modes with various operational parameters. The effects of temperature, pressure, and core model type on the hydrogen generation were investigated.Results show that temperature higher than 550 ºC should be achieved in the active zone of the target reservoir to convert significant amount of methane to hydrogen. The lower temperatures reached at the active zone are inefficient for the hydrogen generation. This effect can be explained by the thermodynamic restrictions and negative influence of the original core on catalyst activity. Nevertheless, hydrogen concentrations up to 70.8% mol. and 34.0% mol. were achieved in the experiments at 800 ºC in the presence of the inert (crushed alumina) and the original core models, respectively. At this temperature, strong reducing conditions influence the catalyst activity. Conducted experiments proved the main principles of the in situ hydrogen generation technology and evidenced that hydrogen generation in gas reservoirs is prospective when realized jointly with the catalyst treatment and in situ combustion method. This innovative technology can help humanity decarbonize the energy sector using unclaimed hydrocarbon resources of depleted and abandoned gas reservoirs without greenhouse gas emissions.
Wettability Characterization of Carbonate Rocks Using a Micro-Scale Approach
Authors: Aboushanab Mahmoud Sami , Al Naimi Khaloud , Al Kobaisi Mohammed , Rahman Md Motiur , Arif Muhammad , Mahmoud Mohamed 
Published: March 2023

AbstractWettability is an important factor that influences relative permeabilities and capillary pressure, which in turn impacts the hydrocarbon recovery. Wettability of carbonate surfaces is typically challenging due to their diverse wetting behavior. Wettability has been conventionally quantified using the macro-scale contact angle observations. However, macro contact angle suffers in terms of precise identification of the three-phase contact line. In this study, a new micro-scale approach is presented to determine rock surface wettability. Here we used five different Middle Eastern carbonate samples with different mineralogy. The micro-scale contact angles are evaluated via Environmental Scanning Electron Microscopy (ESEM) using condensation-evaporation approach while the classical sessile drop method is used to determine the macro-contact angles. The results show a notable difference between macro and micro contact angles which suggests wettability variation at different scale of measurement. Depending on micro contact angles, mixed-wet state for all samples is observed, as some samples experienced water-wet behaviour at most of the measured locations, while they showed intermediate-wet behaviour at a few locations. However, based on macro contact angles, only one wetting behaviour is recognized. Therefore, a thorough wettability characterization would require insights at the micro-scale to capture variations in wetting behavior.