bluuebunny/crossref_metadata_2025_split huggingface dataset:
Machine Learning Lessons Learnt in Stick-Slip Prediction
Authors: Gupta Soumya , Chatar Crispin , Celaya José R. 
Published: November 2019

Abstract
Downhole vibration remains a major challenge for drillers. Today, there is technology to look at the problem from a unique perspective. A novel look at the problem focuses on evaluation of machine learning algorithms to predict downhole vibrations. Prediction is the first step in a longer road map. The goal would be to find an optimal combination of revolutions per minute (RPM) and weight-on-bit (WOB) to remedy drilling vibration in real-time, hence closing the loop. Drilling mechanics data for thousands of wells, acquired over more than ten years was analyzed. Some preparation of the drilling mechanics data was required. Data cleaning was first performed. This included corrections for time-dependent nature of the data. Data imputing for missing values and handling of outliers and anomalies was also performed in this stage. This was followed by feature engineering which included adding variables based on company-wide drilling domain expertise. Variables to capture data patterns and variables for better capturing the time-series dependencies were also created in this stage.
This paper will discuss methodologies and general rules that were tested for preparing unstructured drilling data. A few of the machine learning algorithms used as building blocks of our full solution are gradient boosting and random forest. Deep learning models were also tested and the value of these are compared. The results were compiled to decide the best algorithm which could further be used to fine-tune optimum performance. The time series aspect of the data is captured in a moving window. As the window increases, the performance of each algorithm also varied. Also, evaluation of the benefits and drawbacks of each algorithm for the drilling predictions is detailed. Ways to improve the accuracy of prediction for downhole vibrations is also suggested with reference to the results showing the logic behind all recommendations. There will be a summary of the details of each finding and a short discussion on the way forward for the industry.
A Novel Thermochemical Fracturing Approach to Reduce Fracturing Pressure of High Strength Rocks
Authors: Al-Nakhli Ayman , Tariq Zeeshan , Mahmoud Mohamed , Abdulraheem Abdulazeez , Al-Shehri Dhafer 
Published: November 2019

Abstract
Current global energy needs require best engineering methods to extract hydrocarbon from unconventional resources. Unconventional resources mostly found in highly stressed and deep formations, where the rock strength and integrity both are very high. The pressure at which rock fractures or simply breakdown pressure is directly correlated with the rock tensile strength and the stresses acting on them from surrounding formation. When fracturing these rocks, the hydraulic fracturing operation becomes much challenging and difficult, and in some scenarios reached to the maximum pumping capacity limits. This reduces the operational gap to create hydraulic fractures.
In the present research, a novel thermochemical fracturing approach is proposed to reduce the breakdown pressure of the high-strength rocks. The new approach not only reduces the breakdown pressure but also reduces the breakdown time and makes it possible to fracture the high strength rocks with more conductive fractures. Thermochemical fluids used can create microfractures, improves permeability, porosity, and reduces the elastic strength of the tight rocks. By creating microfractures and improving the injectivity, the required breakdown pressure can be reduced, and fractures width can be enhanced. The fracturing experiments presented in this study were conducted on different cement specimen with different cement and sand ratio mixes, corresponds to the different minerology of the rock. Similar experiments were also conducted on different rocks such as Scioto sandstone, Eagle Ford shale, and calcareous shale. Moreover, the sensitivity of the bore hole diameter in cement block samples is also presented to see the effect of thermochemical on breakdown pressure reduction.
The experiments showed the presence of micro-fractures originated from the pressure pulses raised in the thermochemical fracturing. The proposed thermochemical fracturing method resulted in the reduction of breakdown pressure to 38.5 % in small hole diameter blocks and 60.5 % in large hole diameter blocks. Other minerology rocks also shown the significant reduction in breakdown pressure due to thermochemical treatments.
Cable Deployed ESP - Solution to Decrease OPEX Reducing Workover Needs and Retrofitting Existing Completion
Authors: Spagnolo Salvatore , Corti Lorenzo , Guglielmo Carmelo , Luppina Salvatore , Maliardi Alberto , Nambiar Vijay , Mollaev Aslanbek 
Published: November 2019

Abstract
The Fully Retrievable ESP System Cable Deployed (CD) is a new technology which permits the rigless deployment of ultra slim OD Electrical Submersible Pump, able to reduce production loss while waiting for work over: these operations should be performed by a proprietary power and load carrying cable, and should be through tubing with the possibility to retrofit an existing completion.
Based on previous Eni Partially Retrievable Experience, a R&D tender was launched among all ESP contractors interested to identify a complete rigless ESP solution. All technologies proposed were evaluated and Novomet was awarded the contract for the trial installation. Eni philosophy was to select the best candidate well which can be representative of the main criticalities of all Eni asset, in order to export the technology in the majority of operated fields. The scouting was performed among all Eni Geographical Business Units (GBU) and finally a well in Italy was selected to be the best candidate. The aim of the test was to install and operate the ESP for a short period of time, in order to validate the technology and diffuse it among the other GBU interested.
It is important to highlight that the well selected is equipped with a Shallow Set Safety Valve, as common practices for ESP installation, so the R&D test will investigate also the functionality of the insert safety valve.
The paper will describe all the steps needed to go further in a Rigless ESP installation project and all the lesson learnt that Eni can draw for the Oil & Gas Industry. The selected solution allows the retrofit option for the current shut-in wells, thus increasing the business opportunity for this type of technology. It is evident that each ESP solution (standard, partially or fully rigless) has pros & cons that will be discussed in the paper to guide the operator in the selection of the best possible option.
Debottlenecking of Oil Processing Train Capacity
Authors: Ray Tapas , Alharam Faisal Ibrahim , Shayea Mohamed Abdulla , Al Hammadi Ali Saleh , AL-Jarwan Abdulla Humaid , Al-Breiki Jumaan Mohamed , Bani Hamoor Mohamed Ali , Rustagi Nagendra 
Published: November 2019

Abstract
There was an urgent requirement for a low-cost fast-track solution to increase the oil processing capacity in one of the ADNOC Offshore facilities in order to facilitate the scheduled maintainence of the Oil Trains as well as to handle additional production before a new train is commissioned. Capacity of each of the four Oil Trains is primarily limited by the vibration problem of the 1st vessel (Inlet Sphere) in the train, due to which field tests could not be performed to establish Oil Train maximum throughput. It was concluded through detailed studies, including Computation Fluid Dynamic Analysis, that there is no techno-economically feasible solution to overcome the vibration problem of the Inlet Spheres. However, the problem could be circumvented if the extra flow is routed to the downstream facilities by bypassing the Inlet Sphere completely. The objective of this in-house study is to find a low-cost solution to overcome the limitation of the Inlet Spheres and other bottlenecks in the trains. Based on the debottlenecking study outcome, it was proposed to use the stand-by Emergency Sphere - while retaining its original design functionality of handling emergency liquid relief - and its associated Crude Transfer Pump to transfer the additional flow (above the Inlet Sphere allowable capacity) directly to the Inlet Sphere downstream system. Similarly, course of actions were also identified for other bottlenecks. Based on the debottlenecking study recommendations, it was agreed to carry out the modification in two of the four Oil Trains considering the Crude Transfer Pump capacity limitation as well as to keep the cost to minimum by maximizing the usage of the existing assets.
Subsequent to the modifications, field tests were conducted and test result showed that the oil-handling capacity of each Oil Train could be increased by 17%. No change in the operating conditions of the existing facilities were required and all the specifications of export crude oil were also met. Based on the test results, other improvements were also suggested. Accordingly, it was concluded to embark on executing the proposed modifications for all the Oil Trains.
The debottlenecking scheme, which is implemented at a cost of ~1 Million USD, is able to generate a revenue of ~2 Million USD per day. Hence, the scheme when extended to the all the four trains would generate a revenue of ~8 Million USD per day. Execution cost for this modification for all the four trains is estimated to be less than 15 Million USD, whereas a new train of similar capacity would cost more than 200 Million USD.
This paper highlights how in-house Technical Support can provide a fit-for-purpose and cost-effective solution to Company’s business needs. The study is a perfect example of "Maximizing Value of Every Barrel Produced".
Unlocking Unconventional Resources in GUPCO: Case Study from Egypt
Authors: Noureldien Darhim M. , Kamal Samy , Hemdan Khaled , Abdallah Hamed , Hassan Alaa 
Published: November 2019

Abstract
The lifecycle of any field consists of three main periods; green, plateau and maturity periods. Currently most of GUPCO fields are brown what made us very concerned to sustain and even increase our production. To achieve that, we have looked at new different options to exploit our resources better. Generally, this can be achieved by whether optimizing current system, applying new technology or evaluating unconventional resources.
One of the high-potential resources that we do have in GUPCO is unconventional resources with many tight carbonate formations. Nevertheless, we did not try to appraise it before since most of our reservoirs are clastics that can be easily characterized and evaluated. On the other hand, tight carbonate formations cannot be characterized or appraised utilizing conventional logging tools or even classical reservoir engineering concepts. It always requires unique techniques relevant to its unique complexity degree especially in presence of micro-porosity and unknown fluid content. This paper sheds light on Appraisal Unconventional Resource Study that resulted in the first successful producer in the company.
GUPCO started to appraise tight carbonate rocks (named Thebes in Lower Eocene) and basaltic intrusion in GoS. This study involved high integration between key disciplines; Petrophysics, Petrology and Reservoir Engineering. To manage uncertainty, we have acquired wide range of data types starting from advanced petrophysical logging tools like Magnetic Resonance, Borehole Imaging and spectroscopy, and full petro-graphic description, reaching to predicting reservoir dynamic performance using measured pressure points (RFT), its analysis and fluid characterization. Ultimately, we have succeeded to completely characterize Thebes formation, and proposing its development plan. The first successful well resulted in 300 BOPD gain as the first successful tight carbonate producer in GUPCO. Development plan is being built to drill new wells targeting unconventional resources including a few possible potential in basalt intrusions, as well.
Dealing with unconventional resources is not an easy task. It requires a lot of work and analysis. Having all of your homework done is not always enough, you have to integrate with interrelated disciplines to link dots and complete the picture. In this paper, we have conceived a new approach in evaluating such formations, and it is a very good example of managing uncertainty by integrating different data to convert hypothesis into reality that can be translated ultimately into oil production and revenues.
A Novel Quantitative and Predictive Reservoir-Souring Approach to Assess Reservoir Souring During Planned-Waterflood Development Plan
Authors: Salimi Hamidreza , Namdar Zanganeh Maryam , McCarthy Sven , Pirlea Lucian , Balushi Haitham , Lawati Mustafa , Yarabi Mohamed 
Published: November 2019

Abstract
Souring potentials of fields during planned-waterflood development need to be investigated to enable the selection of the injection-water source and facility-design options. This paper presents the application of a novel reservoir-souring approach to assess the souring potential of a Middle-East field that is associated with three potential injection-water sources in terms of souring, to recommend ways to prevent or reduce H2S production, and to determine the optimum solution for injection water.
The novel approach includes fluid sampling and analysis, a desktop study, a dynamic-reservoir simulation, and a surface-facility evaluation. In the desktop study, a qualitative assessment of souring associated with the three potential injection-water sources (shallow-aquifer water, produced water, and mixtures of produced and shallow water) and mitigation strategies to limit future H2S concentrations were carried out. Subsequently, a compositional non-isothermal dynamic model that includes 3 phases, 18 components, and 18 reactions was developed to quantitatively predict the most-likely and the worst-case H2S levels over the field’s life. Several sensitivity runs were performed to assess the impact of the key uncertain parameters on the H2S level.
The results indicate that re-injection of produced water (deep aquifer) with a salinity of 173,000 mg/l not only has a very low souring risk, but also offers the most manageable conditions in terms of scaling and corrosion control for both the reservoir and the facilities. For this water, the simulated earliest H2S-breakthrough time is year 2038 and the H2S concentration in the gas phase will not exceed 1000 ppmv until 2074. On the other hand, injection of the shallow-aquifer water with a salinity of 11,000 mg/l has a high risk of souring. The simulated earliest H2S-breakthrough time is 2025 and after breakthrough within one year the gas-phase H2S concentration reaches 1,500 ppmv at ambient conditions. When mixtures of produced and shallow-aquifer water are used, the risk of souring depends on the mixture salinity; if it would be higher than 150,000 mg/l, the souring risk would still be very low, otherwise the souring risk would be moderate to high.
In terms of mitigations, nitrate injection is very effective in significantly reducing the high souring risk of injecting the shallow-aquifer water. Stripping out the dissolved H2S in the shallow-aquifer water can delay the H2S-breakthrough time by 11 years and can reduce the max H2S concentration by 50%.
Successful Evaluation of Tight Gas HPHT Carbonate Formation with Extremely High Sour Content and Elemental Sulphur Presence
Authors: Yugay Andrey , Ahmad Mubashir , Bankole Ibukun Olatunbosun , Alhouqani Shamsa Sulaiman , Al Qallabi Salah Al , Pimenta Gervasio 
Published: November 2019

Abstract
As a part of Country strategy to fulfill growing demand in gas energy in the country, development of Arab formations started. This paper shares the actual case history of successfully completed evaluation of Arab formation in one of the Company fields. High temperature (300F), high H2S concentrations (up to 37% H2S) and presence of elemental Sulphur dictated usage of very exotic downhole corrosion resistant alloy (CRA) material. Tightness of carbonate formation (less than 1 mD) pushed to drill 10,000’ horizontal section to meet project objectives. High reservoir pressure reaching 5,700 psi in combination with all conditions above resulted in high level of risk during initial project evaluation and required very robust HSE and Integrity systems in place with no chance to failure.
Arab formation evaluation project started in 2014 and was performed in several steps, with gradual increase of the complexity of the each next stage: from vertical well to horizontal, from sampling to longer duration testing, from carbon steel completion to fit-for-purpose inhibition and high grade CRA materials. Efficient collaboration among multidisciplinary teams, continuous management support and clear communication channels between all stakeholders proved to be a key to success for this challenging project. The project included involvement of high capacity rig to fulfill extended reach depth (ERD) well requirements, specific well intervention techniques while drilling and testing, usage of special inhibitor for high sour wells and finally inspection of the recovered completion. All Company available best practices and technical competencies applied in this project allowed to overcome all the challenges and achieve appreciable sustainable gas rates, meeting all set objectives with no HSE incidents and failures. Findings and lessons learned received are used to tailor next stage of the project to ensure most efficient scenario of field development to support country strategy in increasing energy potential.
The content of the paper gives a good understanding to the readers on the key aspects and main challenges that they may face during initial evaluation stage of the tight gas high pressure high temperature (HPHT) carbonate formations with high H2S content. The document could be used as a local considering current government strategy of massive attraction of new business partners for the exploration of new gas and gas condensate blocks in the region.
Holistic Approach to Prolong Giant Onshore Abu Dhabi Gas Field Production Plateau and Optimize CAPEX/OPEX Using an Integrated Asset Model as a Digital Twin
Authors: Latif Mohd Anwar , Bedewi Mahmoud , Abdullayev Azer , Al Saadi Noura , Saleem Babar Mohammed , Al Bairaq Ahmed Mohamed , Al Ameri Ammar Faqqas 
Published: November 2019

Abstract
A giant gas field consisting of six stacked carbonate reservoirs of Lower Cretaceous age with gas caps and non-associated gas where the production follows a depletion scheme is discussed. The field has a production history of more than 30 years with more than 150 gas condensate wells flowing to a common surface network, which means production decline is inevitable.
This study assesses various mitigation actions to extend the plateau or minimize the anticipated inevitable production decline, and optimize costs while adhering to a service level agreement (SLA) with the consumer gas plant.
This paper illustrates how the use of an integrated asset model (IAM) as a digital twin of the actual asset can help provide a holistic approach for evaluating critical investment decisions.
The proposed mitigation actions were mainly focused on surface facilities because gas fields are sensitive to backpressure; the mitigation actions were primarily geared toward reducing backpressure to remedy the anticipated production decline.
Gas plant inlet/outlet pressure reduction proved to provide significant plateau extension. This finding was verified by means of field trials. Intermittent and weak producers responded positively to the implementation of wellhead compression during the IAM simulation; consequently, a pilot was implemented in the field to verify the simulation conclusion. IAM also proved that adding 20 new infill wells would help accelerate gas production, if necessary; but, it requires further economic justification before implementation.
Simulating scenarios, such as the segregation of wells currently sharing flowlines, had a minor effect to overall field production. A previous reconfiguration of compressors within the compression stations proved beneficial in mitigating production decline and accelerating gas volume. However, because of operational risks and associated costs, future reconfigurations showed minimum impact.
A significant portion of the study was focused on modeling the downtime of various components of the asset surface facilities as per the integrated shutdown plan (ISDP) and identifying alternative routes to minimize overall gas production disruption and to adhere to the SLA commitment.
The focus on precisely simulating the operational side of the field was enabled by the use of IAM as a digital twin of the actual asset. In addition to the usual simulation benefits, such as the assessment of various sensitivities before implementing significant investments in real life, this holistic approach can help realize cost-saving opportunities and help ensure future adherence to the contracted gas rate.
Proactive Management of Occupational Health using Fatigue Risk Assessment
Authors: Kulkarni Poorva , Al Hammadi Saud , Al Zbeidi Osama , Al Marzooqi Meera 
Published: November 2019

Abstract
Company conducted a Fatigue Risk Assessment Study to estimate the fatigue levels of approximately 9000 shifts and the risk of incidents occurring due to operator fatigue.
The findings provided an insight into the likelihood of fatigue and risk of errors / incidents occurring for approximately 9000 shifts of control panel operators working on a 4×4, 12-hour, day and night shift pattern. The results presented in this paper are limited to the assessment conducted for day shifts in order to demonstrate the methodology.
The study compared different shift patterns in order to identify shifts with higher fatigue levels and identify control measures to reduce operators’ fatigue levels and risk of incidents occurring to As Low As Reasonably Practicable (ALARP).
Lowest fatigue and risk levels were identified for the current 4×4 shifts in comparison to 7×7 and 28×28 shift cycles followed by other Companies. In order, to lower the risk to as low as reasonably practicable (ALARP), additional control measures such as training, campaigns, ergonomic assessments, KPIs such as tracking incidents by fatigue levels, etc. are being rolled-out for implementation.
This is a novel approach on the combination of a qualitative (IOGP) and quantitative (UK HSE) fatigue risk assessment methodology that has widespread applicability, prospectively in terms of shift design and prevention of incidents caused by fatigue induced impairments and retrospectively for incident investigations.
This Fatigue Risk Assessment Study fosters proactive occupational health management by promoting health of employees and preventing / reducing fatigue and thus plays a vital role in the prevention of sickness absenteeism and illnesses associated with chronic fatigue.