bluuebunny/crossref_metadata_2025_split huggingface dataset:
Artificial Intelligence in HSE
Authors: Hojageldiyev Dayanch 
Published: November 2018

Abstract
Artificial Intelligence (AI) is a relatively new concept for oil and gas industry. Yet, its agile nature and massive potential give a promise for constantly evolving oil and gas business in tackling such issues as environmental protection. AI systems utilize a variety of technologies making it possible to produce comprehensive, nonetheless easy-to-use tools, which can be used by Health, Safety and Environment (HSE) professionals in their daily activities. This paper examines a so-called HSE AI Assistant - another tool aimed to provide support to HSE professionals in getting instant answers to questions on a variety of regulatory topics in occupational health, safety, and environmental protection. This AI tool will utilize latest NLP technologies to retrieve data from a bank of up-to-date HSE regulations and standards, and provide answers to required questions. The tool is a much more efficient alternative to traditional search engines and closed intranet data retrievals, as the AI system has an ability to understand human questions, hunt for applicable data in attribute files, and produce the most relevant answer to the questions. The system utilizes latest machine learning technologies, and has a capability of constant learning and evolvement. This will be especially useful in terms of changing local legislation and updates to the HSE regulations. The HSE AI Assistant can also be supplied with a capability to assist HSE specialists in classification of hazardous materials and help to perform regular HSE audits in the areas where hazardous materials are used and disposed. Developed locally in Turkmenistan by a team of HSE and IT professionals, the HSE AI Assistant can become a very accessible and easy to maintain reference and solution tool for HSE specialists working on COSHH audits and environmental impact assessment. The HSE AI can also assist those who control the chemical stock in the warehouse, and who manage the hazardous waste at the disposal sites.
Application of Uncertainty Analysis in the Design of Subsea Natural Gas Dehydration Units
Authors: Kruger Francois J. , Kontogeorgis Georgios M. , von Solms Nicolas 
Published: November 2018

Abstract
Advances in subsea processing present the opportunity for high pressure natural gas dehydration and product export directly from the seabed. In this work we evaluate dehydration using monoethylene glycol (MEG) as an absorbent. A combination of parameter uncertainty and process input sensitivity analysis is used to evaluate the feasibility of 18 different scenarios. For a representative light and heavy natural gas, a 3×3 experimental matrix for processing pressure (60, 90 and 120 bar) and lean MEG quality (90, 95 and 98 wt%) was used. 5000 Monte Carlo simulations were performed for each case with the output mean and confidence intervals being calculated.
In terms of dehydration performance, the feed gas composition has only a minor effect in the order of 2.5%. The process is shown to be infeasible when using lean MEG with a quality of 90 wt%, while the lean MEG flow rate can be adjusted to meet product specification of 32 ppm H2O if higher quality lean MEG is used. The required flow rates ranged between 16 and 254 m3/h. The minimum required lean MEG quality is estimated as 95, 93 and 92 wt% at 60, 90 and 120 bar processing pressure respectively. From the upper bound of the 99% confidence interval, it is estimated that the minimum safety factor of 5-9 ppm is required (depending on the quality of lean MEG used).
Secondary performance measures were also evaluated. MEG content in the product gas varied most strongly with gas composition (especially at high pressure), where differences of up 150% are seen for the light and heavy gas. Product recovery was between 97.5 and 99% for the feasible cases with the best recover found at high pressure and lean MEG quality, while recovery of light gas was slightly improved compared to heavy gas.
Fibre Optic Surveillance for Conformance Monitoring in a Polymer Pilot by Petroleum Development Oman
Authors: Rawahi Zainab , Hemink Gijs , Freeman Floris , Groen Alex 
Published: November 2018

Abstract
Petroleum Development Oman (PDO) has been utilizing several Enhanced Oil Recovery (EOR) methods in the Sultanate of Oman to accelerate (polymer/steam floods) and increase (Alkaline Surfactant Polymer, or ASP, floods) recovery from fields with challenging rock and fluid properties. Polymer-flood is a mature EOR technique, and has been trialled and implemented successfully on full-field scale in a sandstone reservoir of excellent quality in the South of Oman.
As part of this continuing effort, a currently ongoing polymer pilot focuses on testing the ability to sustain polymer injectivity and to prove the polymer efficiency in a significantly lower permeability sandstone reservoir. This lower permeability reservoir introduces injectivity and conformance concerns. Continuous surveillance to monitor and assess changes in areal sweep, vertical conformance and fracture initiation play therefore a pivotal role in delivering on the success criteria of the pilot. The pilot was designed with this surveillance scope in mind. Producers are equipped with either a dual well-head or a permanent down-hole gauge, and well-testing is conducted with a dedicated [mobile] test-unit. In the injector wells verifying vertical conformance and matrix injection is critical but conventional surveillance (Production Logging) is unreliable as the spinner is affected by the non-Newtonian behaviour of the polymer solution. The two pilot injectors were therefore equipped with a fibre optic (FO) cable, clamped and cemented on the out-side of the 7″ casing, enabling continuous monitoring of the injection profile and thus injection conformance through temperature (Distributed Temperature Sensing, DTS) and acoustic (Distributed Acoustic Sensing, DAS) measurements.
The focus of this paper is to explain the decisions taken based on the information obtained from the FO data during the pilot period. The data was used for several key decisions; to select which pilot injector to use for polymer injection and which to keep as a back-up by assessing Out-of-Zone Injection, matrix versus fracture injection, and to prove conformance and injectivity improvement after acid stimulation jobs. The most valuable information inferred from the FO data allowed confirmation of the improvement in injection conformance by the polymer-flood over the water-flood. Fibre optic surveillance thereby has truly proven its surveillance value, for this polymer pilot, and any potential up-scaling of the project.
Efficiency, Economics and Compliance: A Practical Planning Tool for Optimizing Cuttings Treatment
Authors: Chauvin Earl 
Published: November 2018

Abstract
The expanding focus on total cost of ownership (TCO) in the oilfield is driving the application of global best practices in drilling and completion operations. Measurable benefits can result from a proactive approach to separating, treating, and handling disposal streams that accounts for both short- and long-term effects and is tailored to the specific needs of projects in the Middle East. This paper provides a versatile decision-making tool to help determine the optimal processes for a variety of conditions based on efficiency, economics, and sustainability.
The most effective treatment solutions and services seek to address multiple factors, including logistics and expenses, drilling efficiency and performance, remote locations with infrastructure limitations, and strict environmental regulations. Interdependencies between the fluids, equipment, and services will also influence the selection of appropriate separation and treatment processes.
A useful decision tree is based on the critical goals of waste volume reduction and maximum recovery of valuable components. Making the right choices in both of these areas will provide effective long-term results and economic benefits.
This paper summarizes multiple case histories that demonstrate successful cuttings and waste stream processing, including both land and offshore operations. In some cases, a mobile or well-specific treatment system works best; others rely on a central treatment facility to serve an entire field or multirig operation. The results achieved in each case contribute to a step-by-step planning tool in matrix format that can be used to design the best set of equipment and services for each location.
The matrix accounts for many factors, including rig equipment and capacities, proposed drilling and completion fluids, lithology, risk assessment, system maintenance, potential process rates and throughput, mobilization, environmental regulations, and infrastructure requirements.
The decision tree presented facilitates the treatment selection process by incorporating useful benchmarks for volumes, process rates, expected base oil/fluid recovery, installation costs/requirements, scalability, longevity, and decommissioning (and/or relocation of the treatment system). It provides a practical starting point for planning an efficient, fit-for-purpose treatment configuration, scaled to match operational needs, reduce total cost of ownership, and meet or exceed existing and future standards.
First Successful Chemical Application Water Shut Off Job in Dual Completed Well Short Tubing and Oriented Perforations to Enhance Well Productivity in Burgan South Kuwait
Authors: AL-Rashidi Alyah , Jain Manish , Tirkey Naween , AL-Ammar Heyam , Al-Ajmi Salem , Weiss Adrian 
Published: November 2018

Abstract
Greater Burgan Field has been producing from more than 70 years and brings many challenges with the maturing field. During the last decade almost all the new wells drilled were completed as dual completions to simultaneously produce from two different formations in Burgan. As the workover rig activity tremendously increased with the increased number of new wells per year, it has been a constant endeavor to carry out maximum well intervention jobs possibly by rig less operations to reduce rig related OPEX and well production down time during rig work over.
One of the biggest long term challenges was to carry out well interventions in dual completions short tubing, which was used to be considered inaccessible due to presence of tubing long in the well bore. In view of above, most of the intended well interventions in tubing short were normally used to be proclaimed as work over candidate thereby increasing load on limited work over rigs.
First time in Burgan a dual completion well was carefully identified to carry out water shut off job by chemical application and adding perforation by oriented perforation gun in short tubing. The tubing short was producing from BGSU reservoir and became ceased to flow due to lateral water encroachment which was evident from the recent PNC log. The formation layer below BGSM was still having oil potential and was intended to produce after shutting off the upper layer BGSU. The Tubing Long was producing from deeper reservoir BGSL around 1200 BLPD with 50% W/C.
This paper elaborates the procedures adopted during the execution of the job and selection process of the chemical squeeze technology. The best suitable chemical technology was selected after carrying out a careful & detailed approach towards different vendors. The step by step detailed program was prepared to squeeze the chemical in to existing perforations, cleaning to the desired depth, testing the squeezed perforations and adding new perforations below with oriented perforations gun.
The results were quite encouraging with sustainable oil gain of 1400 BOPD and the detailed cost/pay back analysis indicated the payback period of only 1.5 days of production.
This successful job has opened a new era in the history of Burgan field and many other water shut off jobs may be successfully carried out without the need of rig work over. This not only will reduce the work load on rig work overs and save rig cost significantly but will also allow to increase the well productivity with a very short period of well down time.
Efficient Pulse Neutron Logging for Uncertain Water Salinity in Carbonate Reservoirs: A Case Study from Offshore Abu Dhabi
Authors: Amer Mohamed Mostafa , Serry Amr Mohamed , Afzal Nusrat Afrin , Al Zaabi Fatema , Al Jaberi Salem , Zhou Jiheng , Ismail Mostafa , Nada Al Sayed 
Published: November 2018

Abstract
Pulsed neutron logging is currently the most commonly used technology for cased hole formation saturation analysis, providing data for reservoir monitoring and management. The common pulsed neutron log measurement is the formation capture cross section (Sigma). The data can be logged at a relatively fast logging speed. Water saturation analysis using the Sigma log requires high porosity and known formation water salinity. Errors in the Sigma log interpretation can result from the uncertainties of water salinity values, which usually change, for example, due to mixing of the hypersaline formation brine with the low-salinity injected seawater. Heterogeneity and changes in the carbonate petrophysical properties also play a role in magnifying the magnitude of water salinity changes. Carbon/ oxygen ratio logging (C/O) is salinity-independent and can be applied to overcome the problem, but the physics of the measurement usually require multiple passes with lower logging speeds than Sigma logging. This paper introduces a novel pulsed neutron logging methodology to help overcome the mixed-water salinity problem and produce a reliable water saturation interpretation for updating fluid front maps.
First, the pulsed neutron tool was operated in Sigma mode to cover the full target reservoir interval in a single pass. The tool was then switched to the C/O mode with multiple passes for 50ft only at the top of the target reservoir. Monte Carlo modelling was applied to the C/O data to calculate the water saturation. The C/O result was then used with the Sigma log data to inversely calculate the Sigma water using a Sigma-based material balance equation across the same interval. The final water saturation across the full interval was estimated by using the calculated water salinity and the Sigma data.
Through the application of the proposed methodology, we successfully measure the target formation saturation information in an acceptable operating time, when compared to conducting the conventional C/O logging across the full interval. The results show that the estimated formation water salinity is close to that value of drilling mud filtrate; the water saturation is slightly lower than that from the openhole resistivity interpretation.
This paper introduces how to optimize a pulsed neutron logging program that combines the C/O and Sigma measurements to enhance the offshore operations efficiency, minimize the water saturation interpretation uncertainties, and support future field development planning.
SCCO2 Flushing Technology: The Supercritical Revolution
Authors: Amundsen Espen , Juul Mikkel 
Published: November 2018

Abstract

Objectives
Research indicate that 80% of all failures in fluid transfer systems are caused by contamination.
Contamination causes huge gaps in both safety and reliability and shortening the lifespan of, systems. Subsea systems are often controlled by very long umbilical's/control-lines (&gt;6 km) with no efficient cleaning option. It is necessary to clean these lines with turbulent flow, which can be difficult to obtain with conventional cleaning fluids

Method
With the Super Critical CO2 (SCCO2) technology, it is now possible to clean very long narrow pipes with turbulent flow, not possible with conventional flushing methods. Due to the very low viscosity, diffusivity, and no surface tension of the CO2, it possible to reach a level of cleanness never seen before. Using the pressure & temperature it is possible to manipulate the density needed to carry the particles. When the particles are carried out of the system, the liquid CO2 is converted into gas in the separator, and the contamination suspended in the CO2 drops out.

Results
This technology has been proven on a proof of concept test (onshore) with two 3rd party participance, flushing a 6,5km ¼" dual control-line. This line was cleaned with laminar flow (Reynolds No. under 3000) and had a certificate that said it was cleaned to NAS1638 grade 6. It was proved, using SCCO2 with a Reynolds No. of 42.000, that the line was not clean, [and was NAS1638 grade 12]. It was then cleaned to NAS1638 grade 3, best we have ever seen. Also, the SCCO2 technology was proved offshore, by cleaning a 38km ½"ID Umbilical for Wintershall Noordzee, from NAS1638 grade 12 to Grade 3 with a Reynolds No. of over 30.000. This umbilical had the same issue as in the proof of concept test. The line was claimed to be clean, but the operator experienced that the chemical injection line was blocked by contamination. This caused a lot of shutdowns and was very costly. After the umbilical was cleaned with the SCCO2 technology, the operator has not had any shutdowns due to contamination or blockages for over 9 months now.

Novelty
With the SCCO2 technology, it is possible to clean or unblock very long tubes/lines, to a cleanness never seen before. The cleanliness and unblocking possibilities are a result of the unique characteristics of the CO2, and the high Reynolds No. possible by using CO2. This opens more possibilities that previously was not possible and lacking in the industry. It will make the systems more safe, reliable and reduce cost and increase the production up-time.
First Successful Replacement of Fully Retrievable ESP by Slickline
Authors: Spagnolo Salvatore , Incollà Francesco , Guglielmo Carmelo 
Published: November 2018

Abstract
Eni installed the world's first offshore Rigless Fully Retrievable Electrical Submersible Pump (RFR-ESP) system in an Eni Congo field in April 2012. The ESP failed after four years, and the system was successfully replaced rigless, by means of a slickline unit and a pumping unit.
The job included the complete path from design and operations definition to the ESP commissioning and follow-up.
Replacement operations were split in three different phases: Pull Out Of Hole (POOH): retrieval of the system and verification of the failed item(s).Run In Hole preparation: order, shipment, test and preparation of the items to be run in hole.Run In Hole (RIH): system deployment, commissioning and follow-up.
The separation in time of the three phases was mainly due to the logistic arrangements required for the shipment of the various items to be replaced.
Major attention was given to HSEQ aspects in every phase.
The job resulted in the complete rigless replacement of the retrievable part of the ESP system, which allowed remarkable cost savings, compared to a rig intervention for the same scope of work, in terms of both direct costs and gains for avoiding well downtime and production delay.
Better results and further contractions of times and costs could have been achieved by improving the management of operations and logistics. However, being this the first job of this kind worldwide, it was challenging in that no model or benchmark was available at that time.
Some lessons learnt from the POOH phase were directly applied during the RIH phase, while others were reported in order to be implemented in future similar jobs. Since the economic impact of this type of job is remarkable, the sharing of knowledge is key to enhance performance of analogous applications, in a safe and efficient manner.
This paper describes the job performed, explaining the choices made, the criticalities encountered, as well as the lessons learnt and the benefits achieved.
Optimizing the Number of Nodes in Artificial Intelligence Neural Network Using Parallel Computing Methods
Authors: AlBar Abdullah , AlGharbi Salem , AlGoz Ahmad , Yami Abdullah 
Published: November 2018

Abstract
Determining the optimal configuration/ architecture for neural network could be a very time-consuming process. It includes going through big number of scenarios to simulate and validate different architecture. This paper will go over a process for intelligently automating this tedious task by providing a utility that will automatically validate the different permutation and picking the optimum configuration. This is done with maximum efficiency by utilizing parallel computing methods combined with in-memory tables to produce very fast result. The new methods enabled Exploration and Producing (E&P) data scientists to simulate and validate a big number of neural network configurations/ architectures in shorter time, allowing them to identify the optimum neural network configurations that can generate the best prediction results. Leading to more accurate Artificial Intelligent/ Machine Learning (AI/ML) models. To quantify this method, this paper approach can cut the time needed for such process from weeks to hours, especially when dealing with modeling E&P real-time problem. The process involved utilizing parallel computing methods combined with in-memory tables, not only in processing complex Artificial Intelligent/ Machine Learning (AI/ML) models, but also in developing the complex models. This approach is intended to empower data scientist in the Exploration and Producing field to quickly reach the most optimize model, leading to faster approach for safer, and more cost-effective solutions
A Success Story of Production Improvement in a Deepwater GoM Field Based on Integration of Surveillance Techniques
Authors: Gonzalez Fabio , Gonzalez Doris , Carmichael Steve , Stewart Carlos , Pietrobon Marney , Garzon Francisco 
Published: November 2018

Abstract
Integration of well and reservoir surveillance techniques: production measurements, reservoir fluid characterization, pressure transient analysis, production logging, relative permeability, and fractional flow are critical in understanding well and reservoir performance for an adequate well and field management specially in a high cost interventions environment.
Well productivity deterioration for a specific well was identified based on production testing and well performance nodal analysis (NA). The productivity deterioration was then confirmed by means of pressure transient analysis (PTA). Standard diagnostic derivative analyses suggested that permeability decrease was the main source of performance detriment due to an apparent transmissibility reduction of 60%. Since water breakthrough took place before productivity impairment was acknowledged, the immediate reaction was to establish the hypothesis that effective permeability reduction due to relative permeability effects was the main reason for the impairment. A multilayer (ML) PTA type curve model together with fractional flow analysis did not support the relative permeability premise as the primary cause, leaving the potential for severe plugging of the reservoir rock as the predominant hypothesis.
A production logging tool (PLT) was run confirming that about 60% of the completed interval was not producing at the expected levels. It was possible to separate the relative permeability effects from the plugging effects using the integrated technique described above. Relative permeability effects contributed to production impairment with an equivalent effective thickness of 14% and plugging effects impacted an equivalent effective thickness of 46%. A coiled tubing (CT) mud acid treatment was performed recovering approximately 65% of the transmissibility lost and decreasing formation skin from 16 to 9. This intervention delivered an instantaneous oil production benefit of approximately 7,000 STBOD. This analysis approach has been recommended to determine potential benefit of future intervention candidates.
This paper presents an innovative approach to consider fractional flow as part of pressure transient analysis interpretation. This level of integration is not a common practice because PTA theory was developed for single phase and most of the commercial software products do not consider multiphase interpretations in analytical PTA. These limitations leave out the actual effect of relative permeability in the estimated transmissibility values.