bluuebunny/crossref_metadata_2025_split huggingface dataset:
Operational Excellence Review through Self-Assessment
Authors: Badithela Srinivas , Al-Haddadi Mohamed Ali 
Published: November 2019

Abstract
Oil and Gas, Petroleum Refining Industry is undergroing through significant Business Challenges, Transformation and Consolidation. Refinery Business Economics has been encountering increased challenges due to significant variations in the market dynamics. Refining Optimization has acquired renewed importance in the past decade and optimization of the existing facilities has become a key component in the overall Business Strategy. Operational Excellence forms the necessary attribute for Optimal Business Performance of the Progressive Companies. Operational Excellence and Business Excellence are the key focus areas for Petroleum Refining Industry in the Middle East and Other Regions. Operational Excellence and Business Excellence requires best in class performance in all the functional areas of relevance to the Business. Operational Excellence and Business Excellence are closely inter- related and complement one another towards superior Business Performance. Operational Excellence Groups in the company deal with activities that would help to inculcate culture of excellence and help in the effective implementation of continuous improvement activities across the company facilities. Periodic Assessment of Operational Excellence is extremely important for identifying the status and take necessary corrective measures /additional measures towards continuous improvement. ADNOC Refining has been involved in Operational Excellence activities and Business Excellence activities for the past two decades with and without the involvement of external consultants. This paper deals with key aspects of Operational Excellence review and methodology of systematic implementation, key challenges, and experiences of first of its kind simultaneous implementation across ADNOC Refining Operating Facilities.
Design of Foam Gas Shut-Off Pilot for a Giant High-Temperature, High-Salinity Carbonate Reservoir
Authors: Elhassan Mohamed , Keshtta Osama Mohamed , Berrim Ahmed , Draoui Elyes , Mogensen Kristian , Levitt David 
Published: November 2019

Abstract
This paper describes preparations and planning for a campaign of foam gas shut-off pilot operations in a large carbonate reservoir located offshore Abu Dhabi containing an oil column in equilibrium with a large gas cap. Throughout the field history and due to the heterogeneity (permeability ranges from 5 mD to 1 D), the major challenge to produce the oil rim independently from the gas cap was how to control premature gas breakthrough in the oil producers. Mechanical interventions in high gas-oil ratio wells are particularly complicated due to the risk of losing oil potential and are generally unsuccessful.
Injection of foam for gas shut-off (FGSO) is a near-wellbore treatment, which has been trialed elsewhere in the industry with some success. Foam can act as an auto-selective agent to shut-off confined gas inflow through a gravity-controlled source like coning or cusping, while oil breaks the foam, resulting in preferential oil flow and reduction in gas-oil ratio. In addition, this type of operation has been identified as an EOR enabler, because it can help prepare for the technical and logistical challenges of using EOR chemicals in the field, generate data useful for the modeling of surfactant and polymer under reservoir conditions, and mitigate early gas breakthrough in the case of gas-based EOR developments.
For the reservoir in question, a key complicating factor was to identify a surfactant, which could generate strong foam in-situ (mobility reduction factor of 50) at harsh reservoir conditions (temperature of 220-230 °F and water salinity above 200,000 ppm, including 20,000 ppm divalents), with an acceptable level of adsorption. The candidate selection process took into consideration overall behavior of the reservoir as well as performance of the individual high-GOR wells. Target well selection criteria included homogeneity of permeability, an understanding of gas sources and their movement, and observation of a rate- or draw-down-dependent GOR.
The experimental lab program involved testing several surfactant formulations in bulk as well as in corefloods with and without the presence of reservoir oil to evaluate foaming ability and level of gas flow reduction. One formulation showed the right level of in-situ mobility reduction, in addition to stability and moderate adsorption at the prevailing reservoir conditions, and was therefore selected for a pilot test involving four wells.
Mitigation of Scaling Potential of Seawater in High Temperature Environment Using Phosphonate Scale Inhibitor
Authors: Yamak Raafat M. , Nasr-El-Din Hisham A. , Rahim Sabiq , Taleb Moussa 
Published: November 2019

Abstract
Laboratory analysis was conducted in order to study the effect of a phosphonate scale inhibitor on a mixture of hypersaline Arabian Gulf seawater and formation water under high temperature/high pressure (HT/HP) applications. The objective of this study was to identify the minimum scale inhibitor concentration required at various temperatures to achieve a cost-effective solution in minimizing the formation of common oilfield scales. Development of such a product would aid in the utilization of seawater-based fracturing fluids by controlling the scaling tendencies of the system, especially when exposed to formation waters. Utilizing a scaling software, various types of scales were modeled by testing different seawater/formation water ratios at temperatures ranging from 270 – 330°F. A dynamic scale loop was used which allowed seawater and formation water to be pumped into the system, thereby generating differential pressure data. The exponential increase in pressure would indicate scale formation. Various concentrations of scale inhibitor were then introduced to the mixtures and tested to determine the minimum scale inhibitor required for scale mitigation. Compatibility tests were also conducted to test for the efficacy of the scale inhibitor.
Based on the scaling software, barite was identified as the primary scale generated. Barite scale has a low solubility of 2 mg/L and is one of the most difficult scales to mitigate. The highest concentration of barite scale occurred in a 50/50 ratio mixture of formation water and seawater. For all the temperatures tested, the scale loop was run at the concentration with the most barium sulfate present. The results for this research concluded that at 270°F and 300°F, the minimum scale inhibitor concentration was 2000 ppm and 1500 ppm, respectively. Both treatments successfully mitigated the following types of scales: barium sulfate, calcium sulfate(s), and strontium sulfate. At 330°F, the minimum scale inhibitor concentration was lower. This decreasing trend in scale inhibitor concentration as temperature was increased is attributed to the temperature constraint of phosphonate scale inhibitors. As a result, adding the phosphonate scale inhibitor contributed to the formation of calcium phosphonate complexes that led to the rise in pressure in the scale loop test. This hindered the efficiency of the treatment and portrayed the dramatic effects of temperature and inhibitor concentration on scale mitigation. This research pushes the thermal constraints of a phosphonate scale inhibitor up to 330°F to test its efficiency and overall treatment integrity. There are also fracturing fluid applications introduced utilizing a seawater source with one of the highest total dissolved solids (TDS) concentrations in the world. Barium sulfate and other scales were successfully mitigated at various high-temperature applications for these systems utilizing a phosphate scale inhibitor.
Advanced Survey Management Techniques Allow Zonal Isolation through Successful Well Intersection in Order to Complete a Well as per Original Plan in a Giant Mature Field offshore Abu Dhabi
Authors: Abdelkarim Islam , Jadallah Haitham , Ness Knut , AL ALI Salim , Alzaabi Mohamed , Amer Reem , Diaz Nerwing , Gjertsen Morten 
Published: November 2019

Abstract
After completing the drilling phase of the 8½″ section for a well in a giant mature field offshore Abu Dhabi, due to geomechanical challenges it was not possible to run the 7″ liner in a shale formation which was open for a long period of time due to rig repairs (top drive failure in open hole), exposing all reservoirs and compromising the field development strategy. After several unsuccessful attempts to run the liner and leaving a drilling BHA in the hole during one of the cleanout runs, it was decided to sidetrack around the fish to intersect the original 8½″ open hole section in order to recover the original hole and isolate the reservoir flow units from each other, which was critical for the field development since more than five reservoir layers were opened with water and oil bearings increasing the risk of damaging the reservoir integrity due to potential cross flow.
Detailed measurement-while-drilling (MWD) survey analysis was conducted for the original hole in order to enhance surveys accuracy and minimize positional uncertainty. Typical survey management practices were implemented for Sag and Drilling String Interference; other techniques such as Dual Inclination, In-Field Referencing, and Multi Station Analysis were also applied. The implementation of these different survey management practices and their respective results are covered in detailed in the current article. Comprehensive planning was carried out, the sidetrack was accomplished and the original hole was successfully intersected at the first attempt.
The advanced applied survey management techniques were crucial, particularly in the absence of magnetic ranging as the interval to intersect was open hole. The outcome of these corrections resulted in a shift of 8ft to the final well position, ensuring the correct direction and position for a successful attempt to intersect the well. This intersection was particularly challenging as the original hole had a 3D profile, thus it was critical to minimize both vertical and azimuthal uncertainties. Intersection was achieved with an RSS BHA, and the success of this intersection without magnetic ranging capability was only based on following a planned well trajectory that intersected the original hole surveys, clear validation of the accuracy of the surveys for both original and sidetrack holes. Achieving this challenging directional drilling goal allowed the completion of the well as per original plan, which was critical for the field development plan of these reservoirs.
Based on the fact that there is very limited existing literature covering similar cases to the one presented, this current case represents a solid successful reference to be replicated in similar cases in the future covering these challenging applications of advanced survey management techniques.
The First Application of a Novel Cased Hole Selective Multi-Zone Sand Control Completion in Gulf of Thailand
Authors: Khunmek Thanudcha , Chigbo Ikenna , Sreeroch Asaduwut , Abu-Jafar Feras 
Published: November 2019

Abstract
This paper will discuss completion design and the deployment method of sand control for multi-zone completion wells in the Nong Yao field. The discussion will cover sand control and completion techniques from given reservoir characteristics, in combination with the production strategy. Operational challenges from offset wells will be discussed.
The Production strategy for the field required careful consideration for the unconsolidated nature of the reservoirs. An effective drawdown strategy is required as Electrical Submersible Pumps (ESPs) are deployed for artificial lift. The teams designed and implemented a cost effective multi-zone completion (MZC) with selectivity and sand control. The completion was designed to fit in a 7" 23# casing and is comprised of a lower and an upper completion. The complexity of the lower completion; 4" sand screen as outer string, internal 2-3/8" tubing with sliding side doors (SSDs), seal bores and packers, made deployment a challenge with a hydraulic workover unit due to the limitations of stroke length and gin pole.
The completion equipment were selected based on workover operations pipe handling constraint, i.e. stroke length, gin poling hanging weight.
As the workover stroke length is only 10 ft., R2 range screen and blank pipe was selected instead of the typical R3 range to prevent screen damage when passing through the stationary slip of the workover unit. Moreover, the total screen length combined with blank pipe has to be designed to meet the sand control objectives and stay within the gin pole hanging weight limitation. The lower completion was completed for selective production zone by zone, and was followed by an upper completion (Y-Tool and ESPs) to produce the hydrocarbons.
The first well completed as a MZC with selective sand control has been on production for more than six months with no sand checking the base sediment and water (BS&W), even though the well has produced at high water cut and at relatively high rates. This observation shows that the implemented completion design along with production start-up strategy is working well. This same strategy is being applied in future wells.
Auxiliary Boilers Energy Performance Benchmarking
Authors: Al Ktebi Waneya Abdulla , Sajjad Saqib , Al Jenaibi Eisa Salem 
Published: November 2019

Abstract
ADNOC Gas Processing, in its journey towards energy excellence, has adopted a novel in-house methodology for energy performance benchmarking. This methodology is primarily focused to unit & equipment level performance comparison, to identify gaps and highlight opportunities for improvement following the best international practices. Benchmarking is an evaluation of any aspect by comparing it with a standard or any other reference at different levels and scales. Generally, in an Oil & Gas Industry, auxiliary boilers mainly consume natural gas to produce steam for process heating. Energy performance of boilers is susceptible to decline due to several reasons and results in reduced efficiency. Owing to the significance of auxiliary boilers energy performance in the overall energy efficiency of gas processing, ADNOC Gas Processing conducted an in-house energy performance benchmarking of auxiliary boilers installed at its multiple sites.
Energy performance of total twenty five (25) auxiliary boilers was analyzed and evaluated in terms of different indices, to examine their current performance and benchmark it with other boilers for potential improvements. Benchmarking also assessed overall steam and condensate systems. Opportunities for improvement were observed in areas of process optimization, best practices and CAPEX based energy efficiency initiatives. Benchmarking exercise revealed energy savings opportunities in flue gases excess oxygen optimization, make-up water management, energy recovery from pressure letdown stations, waste heat recovery and steam traps audits. Study also highlighted areas of improvement in performance monitoring encompassing metering, sustained optimization and continual improvement.
Non Routine Flaring in Upstream Oil and Gas Industry Root Causes and Mitigations
Authors: Al Kamali Maryam Mohammed , Houache Omar , Hasan Hasan Abdellatif , Abdul-Wahab Sabah Ahmed , Agrawal Harshit 
Published: November 2019

Abstract
This study is deep diving in non-routine flaring issues. It focuses on data collection and analysis of non-routine flaring incidents that happened in six (6) different production stations located across Oman in order to define the bad actors that contributed to the frequent equipment failures. These stations have been chosen because they have high flaring frequency and volume compared with other stations located in other parts of Oman. Moreover, risk assessment matrix (RAM) and root causes analysis (RCA) were carried out to help in establishing the bad actors. In addition, for the sake of analysis, comparison between three years is conducted to determine which year has much more representative.
It was found that the main three bad actors are the chiller compressor, gas recovery compressor, and gas injection compressor. Moreover, risk assessment and root cause analysis shows that all bad actors fall under high risk cases, which indicates the criticality of failure of this equipment.
An Integrated Wells to Process Facility Model for Greater Burgan Oilfield
Authors: Desai Sameer Faisal , Al Jadi Issa , Al-Ghanim Wafaa , Franco Francy Milena , Khor Siew Hiang , Zhang Qiong Michael 
Published: November 2019

Abstract
This paper discusses the development of a truly integrated asset model for the Greater Burgan oilfield in Kuwait linking multiple wells, pipelines networks, and process facilities for achieving integrated operational excellence in the South and East Kuwait asset of Kuwait Oil Company. A water handling facility model comprising of two effluent water disposal plants, a crude oil export pipeline network and a water injection network model are also incorporated into this integrated asset model. The main objective behind the development of this integrated asset model is to enable better asset management, faster and more precise decision making and enhancing the hydrocarbon flow path all the way from the reservoir till the export point.
The new integrated asset model was developed from a model centric approach involving construction and calibration of over 1500 well models. All wells were then linked to their network models comprising of pipelines totaling more than 10,000 km. The well and network models were integrated with the respective process facility models of the 14 gathering centers located in the field and finally tied to the crude export, water disposal and water injection systems. The results of the integrated wells to process facility models such as pressure gradient, temperature gradient and erosional velocity ratio gradient across the production network can be plotted or visualized on the Geographic Information System (GIS) map.
Integration of the vast number of wells and network models with the 14 crude processing facilities in a single IAM platform provides comprehensive understanding of flowing paths spread across the giant Burgan field and proves its utility as an effective flow assurance tool. The IAM platform also provides engineers and management an effective tool for analyzing well potential, identifying under-performing wells, spotting clusters of high water cut wells, singling out back pressure effected wells and locating system constraints. Thereby the proven IAM provides valuable information for effective production optimization and long-term surface facility development plans.
The IAM platform is designed for use by Reservoir, Production, and Process Engineers as well as Operations, Business Development, and Asset Management teams. Engineers can evaluate various scenarios to improve production and operation performance such as choke increase or decrease, re-routing wells between manifolds, adding new wells into the system, and decision on slots for connecting new wells to the plant headers. The IAM also enables asset teams to forecast injection rates, review the impact on the entire injection network in terms of pressure distribution, and conduct "what if" scenarios leading towards complete asset optimization.
Starting with the End in Mind: The Path to Realising Digital Value
Authors: McLachlan Duncan 
Published: November 2019

Abstract
In this paper we will set out how we maximise the value created by the digital revolution through the use Systems Thinking and Agile techniques to establish a FEL 0-1 Digital Twin, we will then describe how we use a BIM approach to evolve this Digital Twin through the project lifecycle; fostering collaboration, breaking down siloes, creating and protecting value as we do so. Two case studies, one an offshore gas compression project and the other a normally unmanned wellhead installation, will be presented to demonstrate the application and effectiveness of this approach.
Flowback Analysis of Complex Fracture Networks in the Unconventional Reservoir Using Finite Element Method with Coupled Flow and Geomechanics
Authors: Li Jun , Liu Yuetian , Xue Liang , Cheng Ziyan , Kong Xiangming , Li Songqi 
Published: November 2019

Abstract
After fracture treatment in unconventional reservoirs, the in-situ stress and fluid pressure are greatly changed in the reservoir because of the generation of fracture networks. In order to get high production, efforts are made to get close fracture spacing and long fracture length in-situ field, which in turn make fracture distribution become complicated as the range of fractures size and density is widespread.
In this work, the finite element method is used to analysis flowback around hydraulic fracture among complex fractures networks, which consider the coupled effects of flow and geomechanics.
The reservoir is assumed to be a 3-D poroelastic medium. According to the fracture sizes, the fracture is divided into three types. These small natural fractures are treated as SRV regions, hydraulic fractures, natural fracture in middle and large sizes are explicitly represented using LGR. Finite element method simulates fracture deformation and the two-phase fluid flow in the reservoir during flowback stage. The physical properties are altered by the coupled flow and geomechanics in the reservoir.
The fluid pressure, stress and flowback production over time around these fractures are recorded. The results show that during the flowback period, the production experience a sharp decrease. The porosity and permeability in the reservoir are greatly reduced because of the coupled effects. These explicit natural fractures influence the hydraulic fractures. As the hydraulic fracture spacing reduced, the stress shadow effects become more serious and the flowback production decreases.
This work helps understand the flowback analysis with coupled geomechanics and flow effects in the complex fracture networks in the unconventional reservoirs and physical properties effects in different reservoir conditions.