bluuebunny/crossref_metadata_2025_split huggingface dataset:
Multistage Horizontal Hydraulic Fracture Optimization Through an Integrated Design and Workflow in Apollonia Tight Chalk, Egypt from the Laboratory to the Field
Authors: Salah Mohamed , Orr Doug , Meguid Ahmed Abdel , Crane Brady , Squires Scott 
Published: November 2016

Abstract
The key challenge in unconventional gas plays covering vast geographical areas is locating the regions in the reservoir with the highest combination of reservoir and completions quality. This allows operators to evaluate not only the richness of their resource but also the ability of the reservoir to produce hydrocarbons in commercial quantities.
This paper discusses hydraulic fracturing designs targeting tight gas in horizontal wells drilled in the Apollonia tight chalk formation in the Abu-Gharadig basin, Western Desert, Egypt through the integration of laboratory, geological, petrophysical, geomechanical, fracture simulation, and diagnostic fracture injection test (DFIT) analysis.
Laboratory testing, which included scanning electron microscopy (SEM) and X-ray diffraction (XRD), was conducted to determine mineralogy and potential damage mechanisms. Fracturing fluid chemistry was tested and optimized using core plugs from representative reservoir rock (fracture conductivity, fracturing fluid compatibility, surfactant type, fracture regain permeability, and scale tendency).
Geomechanical rock properties derived from advanced petrophysical analysis of newly acquired high-definition triple-combo full-wave sonic logs and core samples were combined with geological parameters and potential treating schedules to develop sophisticated fracture simulation models. These models were then refined with in-situ reservoir data obtained from DFIT analyses to derive the final fracturing treatment design.
The stimulation model was built using a three-dimensional (3D) geological model with multidisciplinary inputs, including formation properties, in-situ stresses, natural fractures, and completion parameters (i.e., well orientation, stage and perforation cluster spacing, fluid volume, viscosity, and proppant volume, size, and ramping schedule).
The integration of all available data resulted in an optimized fracture design that helped reduce both cost and formation damage, thus improving flowback, long-term productivity, and profitability from this tight formation.
Preventing Catastrophic Failure by Timely RCA Intervention & Fault Restoration.
Authors: Rashad Hatem 
Published: November 2016

Abstract
This RCA case study has been initiated before the Gas Turbo generator failure took place by timely intervention when the Gas Turbine incident alarm triggered.
Root cause analysis (RCA) process was introduced in ADGAS back in 2004, the process was designed to ensure the elimination of defects and incidents with an integrity exposure or causing production losses from repeating by identifying the root cause and putting in place robust actions to ensure incidents don't reoccur. The RCA process enabled ADGAS to put in place a practical methodology for the initiation and execution of an investigation to resolve an incident that could cause a significant loss in production, Loss of functions and / or process contamination, an integrity risk or a repetitive problem that had to be eliminated. The RCA findings would have to undergo a review before the findings and actions are approved and issued.
LG6 Gas Turbine is generating 1/3 of Das Island electrical power and very critical for ADMA / ADGAS production sustainability. In May2011 LG6 encountered a severe failure of its Gear Box, entire mechanical package misalignment, load coupling compression, severe foundation tilting and load gear box tilting. The inspection findings revealed a high risk of coupling destruction and production losses. Risk assessment highlighted that if the coupling damage while machine running, it could cause a flying objects to surrounding by 30.5 meters away and 4 meter width.
This RCA case study has been initiated before the LG6 power generation Gas Turbine failure took place by timely intervention when the Gas Turbine incident alarm triggered. Risk has been assessed and decision made to shut down the machine immediately for site investigation and remedial actions. RCA team members faced a big challenge to get the machine back in service safely and efficiently as soon as possible to save the plant production and avoid bad reputation of partial electrical power off- black out. This also saved a company a rental fees of pack up power generation unit (estimated 24 MM US$ for two years) and assure providing of the required power to keep the operation of LNG, OAG trains and commission of IGD projects on time with no power shortage.
This project resulted in significant potential enhancements for all of the ADGAS Turbo machinery units through the innovative application of a proven root cause analysis and remedial actions to identify the truly underlying "root causes" of incidents and developing sustainable repairs. Using a fault tree analysis process this project successfully identified 85 critical possible causes for the rare Frame 5 Gas turbine fault, eliminate by verification one by one pinpointed the cause of failure and developed a repair actions that prevent failure reoccur.
Design Optimization Challenges During Detailed Engineering: EPC Contractors' Perspective
Authors: Haider Abbas , Singh Bhupinder , Singh Harendra , Kamal Faris Ragheb , Takieddine Oussama 
Published: November 2016

Abstract
The successful completion of Detailed Engineering is influenced by the timely acceptance of design changes proposed by Engineering, Procurement & Construction (EPC) Contractors during design development. EPC Contractors develop the Front End Engineering & Design (FEED) design based on detailed engineering data. A key challenge faced during Detailed Engineering is that Companies tend to be unfavorable towards the design optimization proposals by EPC Contractors. This paper attempts to discuss some of the challenges based on examples from projects executed in the recent past.
During Detailed Engineering, multiple design reviews are held by the EPC Contractor, together with the Company. During these reviews, all design changes, i.e. additions and deletions from the FEED design, are discussed. While the approach that Companies have towards design additions is encouraging, the same cannot be said towards design optimization proposals that EPC Contractors attempt to bring out. More often than not, Companies insist that EPC Contractors follow the FEED design, even though the proposed optimizations offer improved design.
EPC Contractors develop the design, based on detailed design data, including data from vendors and results from specialized engineering studies etc., which are not available at the FEED stage. Therefore, EPC Contractors are better equipped to analyze the design optimization opportunities. Even though EPC Contractors are responsible for the detailed design and performance guarantees of the project facilities, they are often forced to forego their optimized designs, and use the designs developed at the FEED stage. This raises the fundamental question of defining the basic objective behind "Design Development", i.e. whether EPC Contractors should explore design optimization opportunities, or simply follow the design as received from the FEED stage.
NPCC, as a large EPC contracting Company, is involved in many onshore / offshore oil and gas projects, and has experienced a variety of design development challenges during Detailed Engineering. The paper highlights the design optimization challenges faced during the execution of recent projects and consequences thereof. The paper also proposes measures to effectively handle design development issues, which will provide benefit to all stakeholders.
Deepest Section Drilled Successfully to TD Using an Advanced Air/Foam System in Highly Fractured Formations of Cretaceous Age in Sulaiman Fold Belt, Pakistan – A Case History
Authors: Ashraf Qasim , Khalid Ali , Nusair Mohd. Khair , Luqman Khurram , Hussain M. , Channa Munsif H. 
Published: November 2016

Abstract
This paper reviews the case history of the deepest section drilled using a specially designed air/foam system in the highly fractured carbonates of "Fort Munro & "Parh" in Kup well-1 located in the Sulaiman Fold belt of Pakistan. These carbonates presented numerous drilling challenges in the well. While drilling with a conventional mud system, total incurable losses were encountered. The client attempted to cure losses by conventional means of LCM pills and cement plugs but total losses were continually encountered after drilling just a few meters with conventional drilling fluid. To address the tedious problem of lost circulation, a design of an advanced air/foam system was considered to be used for further drilling.
The paper starts off by discussing the challenges associated with drilling such a deep section with an air/foam system, and how an advanced and more sustainable foam system was designed. Numerous challenges were associated with designing a foam system for the subject well. First; the depth of the section was till 2300 m which would require a foam system to be able to bear its own hydrostatic head, second was the higher than normal formation temperature of 225 deg F which would drastically harm foam quality, and the third & last was that the designed foam system would be able to clean the hole properly at higher drilling rates compared to conventional drilling. The paper will then also present the methodology for job execution and finish off with the delivered results and conclusions.
To summarize, an advanced air/foam system was designed to mitigate total loss of circulation encountered in these carbonates of cretaceous age in Sulaiman Fold Belt of Pakistan. The advanced air/foam system allowed the operator to drill that part of the well to desired depth and successfully cased the troublesome formations. Besides curing the total losses in the subject formations, the operator was able to achieve an ROP which was five times the ROP compared to conventional drilling in the same formations. This paper will highlight the design process used to devise an advanced air/foam system that enabled to drill these carbonates of "Fort Munro" and "Parh" formations in the well. The paper will be targeted towards presenting the design objectives, the onsite execution, and the lessons learned in developing an advanced air/foam system for the well. This will aide in the efficient designing of operations for upcoming wells with similar problems even anywhere else.
NPCC Experience in Fire & Gas Detectors Selection and Layout for Oil & Gas Facilities
Authors: Ali Mariam Abdalla , Jha Ajay Nandan , Singh Harendra , Kamal Faris Ragheb , Takieddine Oussama 
Published: November 2016

Abstract
A reliable fire and gas detection system is vital for early detection of potential hazards and prevents escalation to catastrophic consequences by alerting the operator to take appropriate timely actions and initiating relevant automatic actions; it is more emphasized for relatively congested offshore facilities having limited means of safe personnel evacuation from toxic exposure/explosion hazards. To achieve a reliable fire and gas detection, it is essential to have a robust fire and gas detection system and strategic detectors placement.
There are industry standard guidelines which propose suitable types of fire and gas detectors and provide advice for selection and placement. In addition, fire and gas mapping tools are becoming popular means to justify the correct location of fire and gas detectors. Rapid evolution to fire and gas detection technology has further contributed to the design challenges impacting detector quantity and its associated downstream system design. Ambiguities in Codes & Standards and the approach adopted during various stages of the project often cause over design and burden to Company.
NPCC has experienced variety of challenges and lessons learned in fire and gas detectors selection and layout during EPC stage executed in the recent past. In one project, open path gas detectors suggested at FEED stage were changed to point type gas detectors during the EPC due to multiple cases of line of sight obstruction in the offshore platforms which resulted in a 4 fold increase to gas detector quantity. In another project, fusible plugs were considered during the FEED stage, to detect fire on unmanned well pads. However during EPC, fire and gas mapping study suggested using UV/IR type flame detectors as the fusible plugs cannot be considered for area coverage in the mapping study. This resulted in an additional 116 flame detectors besides the fusible plug type fire detectors. Finally, in another case, fire and gas mapping study during FEED stage suggested using HC detectors to monitor H2S leak at stoichiometric concentration. However, during EPC, it was recommended to use separate HC and H2S gas detectors resulting in doubling of the number of gas detectors.
In conclusion, careful use of available technology and finalization of F&G detection philosophy at early stage of project is the first step for cost-effective solutions. Secondly, close coordination with the Consultant performing the mapping study to avoid unnecessary detectors is required. This paper attempts to outline the challenges and ‘Lessons Learnt’ by EPC Contractor for fire and gas detectors selection and placement. Finally, the paper proposes a way forward for effectively handling the same.
Design a Multiport Completion with Inflow Control Devices: Hydraulic Modeling to Meet Financial Function Optimization in a High Water Cut and CO2 Environment
Authors: Kais R. , Bustamante N. Gomez , Elarabi A. F. 
Published: November 2016

Abstract
The Midale field, located in Saskatchewan, Canada, is one of the largest water-alternate-gas (WAG) injection operations in the world for enhanced oil recovery (EOR). Wells are normally completed across the three main oil horizons of the Marly formation (M1, M2, and M3), with production from all three zones being commingled. Horizontal producers and injectors are openhole wells, whereas vertical wells are usually casedhole. After years of operation, the WAG injected fluids started to communicate from injectors toward producers, resulting in high water and CO2 cuts and making oil production optimization and recovery more challenging. A new completion was envisioned to improve the oil producers’ rates and overall EOR performance. A casedhole vertical well was selected for upgrading into a new adaptable multiport completion, designed to give independent control of each zone. This new completion was designed considering the challenges of the produced fluids, as well as the interaction between each port, the nozzle size of each inflow control devices (ICD), and the financial impact of producing higher rates under the current (2015–2016) market, which is challenged by low oil prices.
The engineering analyses used a steady-state hydraulic well model and a compositional fluid model to consider the impact of the CO2 operating in near critical conditions. Production well tests and laboratory analysis were used to tune the hydraulic well model and the fluid model, respectively. The optimization workflow used the ICD nozzle sizes as decision variables for each port of the new completion, and the financial function, which used reference prices for oil and handling costs for gas and water as coefficients, was maximized by a numerical mixed integer nonlinear programming (MINLP) solver for each case of study. The ICD nozzle sizes were selected for each port of the new completion, based on the hydraulic performance of a series of possible production scenarios, the optimization of the financial function, and the available settings of the ports.
This paper presents the results of an integration of production test separator data, production logging test (PLT) surveys, fluid pressure/volume/temperature (PVT) data, equation of state (EOS) fluid models, hydraulic models, and optimization solvers. These data and models enabled engineers to analyze several possible ICD designs to maximize financial gain.
Reservoir Characterization while Drilling; A Real Time Geosteering Answer to Maximize Well Values. A Case Study, Offshore Abu Dhabi.
Authors: Serry A. M. , Herz U. , Tagarieva L. 
Published: November 2016

Abstract
The objective of this case study is to show the value of the NMR real-time log data, acquired while drilling, for reservoir characterization as a lithology independent porosity logging solution and most important for permeability computation.
The applied methods are being discussed with much focus on the added value of the transverse relaxation time T2 spectrum analysis in a highly heterogeneous, upper Jurassic carbonate reservoir, to characterize the pore size distribution while geosteering the wellbore to track the better quality pore systems and generate a real-time permeability profile, supporting the later advanced completion run for the first time, in this offshore field.
The current field development plans are based on drilling multi-lateral horizontal and highly deviated wellbores along the layers of Reservoir-D to enhance the injection and production efficiency. Running radioactive-based porosity logging tools with such complicated well trajectories poses a high operational risks and collide with environmental regulations, this paper presents a case where nuclear magnetic resonance (NMR) as a source-less porosity logging device, run with the conventional resistivity-gamma ray logging while drilling combination achieved effective real-time formation evaluation and supported efficient well placement to maximize the reservoir contact.
The NMR formation evaluation supported the design of the following Inflow Control Device (ICD) well completion operation for water injection, in a timely effective process, later validated with production logging data. The application is focused on maximizing the value of the real-time LWD (NMR) data for the time-critical (ICD) design and deployment in the highly deviated/ horizontal drains drilled, offshore Abu Dhabi.
Minimize Shaking Maximize Process Safety
Authors: Locharla Haribabu , Narayanan Sathyanath , Awadhi Ibrahim Al 
Published: November 2016

Abstract
Integrity of piping systems is critical for the safe and reliable Plant operations. Shaking or Vibration of piping systems pose potential threats to plant safety and integrity. In GASCO plants, vibrations were observed in some systems such as piping carrying two-phase flow, high pressure lines, piping associated with compressors / pumps, etc. Minimizing the pipe shaking to maximize the process safety through a systematic approach will result in economical, efficient, safe and time bound advantages.
This paper presents GASCO's approach in resolving piping vibrations and mitigating the risks to plant operations.
Studies were carried out to investigate the root cause and recommend required remedial measures. Walkthrough along the piping system was carried out to identify locations of high vibrations and to detect any mechanical abnormalities as first step. Process conditions were also verified for any upsets. This was followed by measurement of vibration parameters such as amplitudes, frequencies and accelerations. The data collected was analyzed and level of vibrations were classified as critical and non-critical based on recommended limits as per relevant industry standards.
For the critical systems, detailed process studies / piping stress analysis were carried out by simulating actual piping vibration taking various excitation sources and as-built conditions into consideration. Theoretical results were compared with field data and were found to be consistent. In order to limit the vibrations within permissible values, necessary measures were recommended.
Based on recommended modifications, revised piping stress analysis was carried out to ensure vibrations are within design limits. Implementation packages were prepared to execute the suggested remedial measures. Post-implementation vibration measurements were taken and observed to be comparable to design values and within permissible limits, thereby ensuring plant safety and integrity.
Less attention paid to piping vibration during initial design phase, probably due to lack of clear and precise codes and standards, was found to be the main reason for piping vibrations. GASCO recognized the need for documenting the above best practices to address piping vibrations. The Guidelines are developed to identify/classify the severity of vibrations and the way forward to tackle the piping vibration issues which can be used by site personnel.
Enhancing Rock Property Prediction from Conventional Well Logs Using Machine Learning Technique - Case Studies of Conventional and Unconventional Reservoirs
Authors: Negara Ardiansyah , Jin Guodong , Agrawal Gaurav 
Published: November 2016

Abstract
It is timely for our industry to introspect on ways for step improvement in the utility of the wireline and logging-while-drilling logs which remains central to any asset development. Interpretation is limited by our current understanding of rock-fluid physics in source rocks, which is still developing. The gap is clearly evident in unconventional source rock interpretation where approximations such as pseudo-Archie approach are used for saturation estimation. This paper presents the use of emerging knowledge in machine learning to demonstrate its applicability for improving the total organic carbon (TOC) estimation in an unconventional well and permeability prediction in a conventional well.
We have used the support-vector regression (SVR) technique, which is a new machine learning technique. Vast amount of logging data can be quickly processed using this technique. Limited core data is used to train the SVR algorithm. In this work, we first use the SVR technique to establish a correlation between conventional well logs (e.g., gamma ray, formation resistivity, neutron porosity, bulk density) and core measurements, thereafter building a rock property-prediction model as a function of well logs selected. Two field datasets from a South American well and a Mississippi Canyon well were selected to validate the method. Both wells contain a suite of logs and few core TOC and permeability data. Various combinations of conventional well logs were studied to check if the prediction accuracy can be improved.
The results of the two case studies reveal that the SVR technique provides accurate and reliable TOC and permeability predictions. We observed in the case study of TOC prediction that incorporating the carbon weight fraction log as an input, in addition to the conventional well logs, improves the TOC prediction because the carbon weight fraction log provides information about the amount of carbon, which eventually helps the SVR algorithm to learn better from the data. Meanwhile, for the case study of permeability prediction, we observed that the conventional well logs are sufficient to generate a good permeability prediction model. Additional logging data including the nuclear-magnetic-resonance (NMR) logging data do not improve significantly the prediction accuracy. In conclusion, SVR technique could be used to improve our log interpretation. This technique can be easily adapted to predict rock mechanical properties and especially useful for unconventional reservoirs where traditional models may not be applicable and new methods are still evolving. Such new data analysis technologies could optimize our logging service and core analysis planning.