bluuebunny/crossref_metadata_2025_split huggingface dataset:
Development of a New Reservoir-Friendly Drilling Fluid for Higher Gas Production
Authors: Al-Yami Abdullah , Al-Jubran Mohammed , Wagle Vikrant , Al-Mulhim Marwan 
Published: November 2018

Abstract
Drilling gas reservoir requires high mud density to balance the reservoir pressure. To formulate such fluids, calcium carbonate (CaCO3) was used because of its high acid solubility. However, due to the high concentration of CaCO3 required for high density drilling fluid, sticking might occur which might result in fishing and/or sidetracks operations. To minimize sticking problems, barite (BaSO4) is added with CaCO3 to reduce the amount of solids needed to formulate the drilling fluid. However, barite can cause potential damage because it does not dissolve in commonly used acids.
Drilling fluids were developed at a wide range of densities using CaCl2 salt with Manganese Tetroxide (Mn3O4). No similar formulations were developed before to the best of the authors’ knowledge. The properties of small particle size (D50=1 microns), spherical shape and high specific gravity (4.9 g/cm3) of Mn3O4 make it good weighting material to reduce solids loading and settling compared to CaCO3 (2.78 g/cm3 and D50=10 microns) and BaSO4 (4.20 g/cm3 and D50=20 microns). The objective of this study is to show the lab work involved in designing water-based drilling fluids using CaCl2 / Mn3O4.
The experimental work in this paper involved rheological properties, thermal stability, API and HT/HP filtration. The data generated from this study showed that Lignite and Vinyl amide/vinyl sulfonate copolymer are recommended to provide good rheological stability and filtration control for CaCl2/Mn3O4 drilling fluid. Polyanionic cellulose polymer and starch can used to formulate KCl/Mn3O4 drilling fluid with good properties at 300 °F.
Challenges of Gas and Oil Mega-Projects: Suhar Refinery
Authors: Kalyanam Sunder 
Published: November 2018

Abstract
EPCC for the Suhar Refinery Improvement Project in Oman

Objectives/Scope: Please list the objectives and/or scope of the proposed paper. (25–75 words)
The Suhar Refinery Improvement Project is one of the largest oil and gas projects ever awarded in Oman. Valued at US$ 2.1 billion, this was truly a ‘mega project in region’ and was executed by Petrofac in Joint Venture with Daelim and successfully completed in 2017.

Methods, Procedures, Process: Briefly explain your overall approach, including your methods, procedures and process. (75–100 words)
Petrofac and Daelim provided a turnkey Engineering, Procurement and Construction and Commissioning (EPCC) solution, which involved upgrades and improvements at the existing facility as well as the addition of new refining units. Delivered through a lump-sum turnkey model, Petrofac leveraged more than three decades of EPC expertise in Oman to shape its local delivery and reduce supply chain costs. Petrofac formed an integrated team with its partner Daelim, the client and JV partners to create a seamless approach, this included a focus group initiative toward flawless start-up as well as the utilisation of common systems, procedures and processes.

Results, Observations, and Conclusions: Please describe the results, observations and conclusions of the proposed paper. (100–200 words)
On completion Sohar's existing output increased by more than 70% to exceed 185,000 barrels per day as well as significantly improving environmental performance. The project's safety performance was exemplary, achieving more than 53 million man-hours without a lost time incident, with a peak project manpower of 14,000.
The creation of In-Country Value (ICV) was a guiding principle throughout, involving the training and development of Omani nationals and the support of local supply chains. The Suhar Refinery Improvement Project was on the winning nomination list that aided ORPIC to win the ICV Strategy Award in 2016. Resourcing was a critical component of the project both in terms of manpower levels required and the drive towards ICV.

Novel/Additive Information: Please explain how this paper will present novel (new) or additive information to the existing body of literature that can be of benefit to and/or add to the state of knowledge in the petroleum industry. (25–75)
This paper aims to showcase the ability of major contractors to work in unison, sharing knowledge and capabilities, to reduce the challenges faced in the execution of mega projects; as well as the role of local content in successful implementation of major projects enabling the development of a capable local workforce.
Enhanced Life Cycle Costing Approach to Tubing Material Selection - New Cost and Revenue Drivers Identified from Experience with Non-Metallics Downhole
Authors: Radhakrishnan Gokulnath , Sharma Ashwani Lata , Venkataraman Eswar , Fernandes Alwyn 
Published: November 2018

Abstract
ISO 15663 Lifecycle cost (LCC) analysis principles are commonly applied to evaluate the viability of downhole tubing materials. This includes the initial CAPEX, operating or maintenance OPEX, Replacement costs and Revenue impact of tubing failure. Increased implementation of Glass Re-informed Epoxy (GRE) Lined tubing has provided significant evidence of flow assurance benefits of the system. This paper will present a modern adaptation of LCC analysis based on operator data and quantification of these benefits and savings.
With over 100,000 GRE Lined completions worldwide there are numerous reported cases of flow enhancements and savings besides corrosion mitigation. The paper is based on extensive research of data collected with agreement from operators representing cost savings or additional revenue that can be factored into LCC analyses with a fair degree of accuracy. Overall operational savings that operators have derived from flow assurance benefits of GRE Lined Tubing, such as improved thermodynamics, scale mitigation, reduced pressure drop, etc. are substantiated using field data from downhole logs, analysis of produced fluids and inspection of retrieved GRE Lined tubing.
Operators have reported higher temperature at well head in Oil Producers after steel tubing was replaced using GRE Lined Steel tubing. This has been associated with savings in separation costs at the surface. There are several reports of higher flow rates and reduced pressure drop across GRE lined tubing which translates to higher injectivity or production. Operators have numerous references of improved and stable flow rates for longer durations when compared to bare steel tubing due to the mitigation of carbonate scale deposition which would impact flow dynamics. Such cases represent significant improvements to production efficiency and, consequently, the overall return on investment in the asset.
The findings of research on multiple operator flow enhancement case references, while implementing GRE Lined Tubing, are illustrated graphically to represent savings and/or additional revenue in comparison with graphical representations of traditional LCC calculations models based on ISO 15663 key drivers i.e. CAPEX, OPEX, Revenue Impact and Replacement Costs.
It is anticipated that this paper will influence a paradigm shift that guides operators to consider the impact of flow enhancement, improved thermodynamics, improved injectivity and/or production, simplification of surface facility requirements and other fringe benefits, in addition to CAPEX, OPEX and Revenue, while evaluating the LCC of tubing material alternatives.
Advanced Assisted History Matching of a Large Mature Oil Field Based on a Huge Number of Grid-Block Level Parameters and Saturation Functions
Authors: Almuallim Hussein , Ganzer Leonhard , Uematsu Hiroshi , Bellah Samir , Virlan Viorel 
Published: November 2018

Abstract
Constructing reservoir models that are consistent with geophysical and geological static data is well understood. A persisting challenge is to condition such models to the available production dynamic data through the process of history-matching. A new algorithm is utilized to identify influencing grid-block properties based on analytical sensitivity calculations. The derived sensitivities allow efficient modification of grid-block properties and saturation functions to improve the history-match. This innovative approach preserves the geological model features, because changes are done at the grid-block level and are only as small as needed to achieve a good match.
Usually, the number of parameters is so immense that engineers have to either restrict their attention to a small subset of the parameters (and likely missing crucial ones), or unnecessarily pay extremely high simulation costs. In this paper, we employ a new assisted history-matching technique that computes the parameter sensitivities analytically and for each grid-block. Here, the derivatives of the mismatch with respect to each parameter are rigorously computed based on the black-oil simulator's fluid flow equations. Hence, a single simulation run followed by a derivatives calculation session is sufficient to detect how each parameter affects the mismatch, and consequently, to decide how (or whether) to change each parameter to improve the match.
This technique was successfully applied to history-match a mature oil field in the Middle East. Two sets of parameters are modified: The permeability in 3 directions per grid block, and relative permeability curves for about 50 saturation regions. The goal was to match water-cut for individual wells.
With this analytical technique, excellent improvement in the match was achieved after only a dozen simulation runs and within a couple of days. Because the modifications are at the grid block level and minimal (only as and where needed), the technique preserves the original geological features of the model to a great extent. Eliminating the need of manual local modifications (e.g. box multipliers) is an important advantage of the method. The relative permeability curves have been tweaked successfully for numerous saturation regions using Corey model parameters. The ability to adjust many curves successfully using just a few simulation runs represents a significant advancement in the field of assisted history-matching.
Cutting-Edge Solutions for Sour Gas Treatment- A Retrospective Study by Kuwait Oil Company
Authors: Al-Ghanem Fahad , Al-Jabri Saleh , Abdul Hameed Mohamed Rizwan , Al-Saeed Mohammed , Al-Otaibi Mohammed 
Published: November 2018

Abstract
Kuwait Oil Company (KOC) owns and operates several Oil & Gas fields and Pipeline networks in Kuwait and is responsible for exploration, development, production and operation of Kuwait's Hydrocarbon assets. The oil fields in the western part of the state predominantly produces high sour gas and normally the compressed sour gas is transported to downstream refineries for treatment, wherein the Acid Gas Removal Plants extract the sulfur contents in the gas received by treating it with regenerative Amine based treating processes for removing acidic impurities such as H2S, CO2 and organic Sulphur compounds.
The country has been long battling with the limitations in downstream sector such as limited handling capacity, unplanned shutdowns, and delay in their expansion projects. This created huge bottlenecks for the upstream unit of KOC which consequently resulted in operational disturbances and gas flaring beyond the company's global flaring target of &lt; 1%.
To overcome these challenges, a comprehensive study was carried out for sour gas handling in the State of Kuwait and installation of Gas Sweetening Facility (NGSF) within KOC was considered imperative. However, the process of project delivery was a great challenge due to emerging operational approaches and conflicts with expansion projects in refinery. Thus, breakthrough solutions were set out deploying appropriate core technologies. This paper discusses the challenges at length and the innovative solutions implemented which were intended to optimize the production and utilization of gas in support of energy requirements for the State.
Asphaltene Precipitation: A Review on Remediation Techniques and Prevention Strategies
Authors: Al-Qasim Abdulaziz , Al-Anazi Amer , Omar Abdulrahman Bin , Ghamdi Muataz 
Published: November 2018

Abstract
In the last few years, large efforts have been made to develop advanced and smart technologies that can predict and prevent asphaltene precipitation. In the history of asphaltene deposition science, two schools of thought have emerged to predict the phase behavior of asphaltene. One school uses colloidal science techniques, believing that asphaltene exists in oil at a colloidal state. The other school adopts thermodynamic methods, believing that the asphaltene occurs in oil in a true liquid state.
The main drawdowns of asphaltene deposition in some reservoirs that are prone to asphaltene precipitation are the alteration of reservoir rock's wettability, and the plugging of the formation, flowlines and separation facilities. Different production strategies have been developed to eliminate or reduce the asphaltene precipitation. As asphaltene properties are dependent on its composition, as well as the reservoir temperature and pressure, thermodynamic and kinetic control strategies are utilized to control the pressure and temperature of the system or the conditions of solid formation. Common intervention techniques include stimulating the well periodically using a mixture of acid, xylene, and mutual solvent. Advancement in the asphaltene flocculation-inhibitor treatments allows it to be used in treating the asphaltene in the reservoir without damaging the formation. There are some limitations and environmental restrictions on the current conventional intervention techniques associated with using low flash-point chemicals. These limitations can be resolved by using environmentally friendly techniques, such as laser energy to disturb asphaltene particles.
This paper will discuss the asphaltene precipitation and deposition phenomena, preventive and detection techniques, and intervention methods and their limitations, providing a comprehensive overview on the current practice in asphaltene remediation and prevention.
Drilling Waste Management – Solutions that Optimise Drilling, Reduce Well Cost and Improve Environmental Performance
Authors: Phillips Laurie , Morris Andrew , Innes Gareth , Clark Adrian , Hinden Pierre-Marie 
Published: November 2018

Abstract
This paper highlights the value associated with the thermal processing of drill cuttings offshore, at source, on an operational and economic basis for a single well drilling campaign.
Treating materials at source eliminates the requirement to transport drilling wastes long distances onshore for treatment and/or disposal, significantly reducing logistics costs and the likelihood of safety and environmental incidents.
The paper outlines a safe, efficient and reliable at source drilling waste management solution that increases operational efficiency, supports well cost reduction initiatives and exceeds regulatory requirements.
It also demonstrates that mobilizing this solution as an onboard drill cuttings processing spread for a one- well drilling campaign is cost-effective.
The paper draws on a detailed case study in which thermal drill cuttings processing technology was mobilized for a one-well drilling campaign on the Orlando field in the UK North Sea, under a contract between TWMA and the Licence Operator but managed by the Well Operator AGR Well Management (AGR).
Using a process of thermal desorption, the solution allows the recovery of three elements from the drill cuttings: oil, water and solids. Recovered base oil, which retains its full original quality, can be reintroduced to the drilling mud system, and recovered water and solids can be safely dispersed on location as they are processed to well within UK environmental tolerances and regulatory requirements. Using the technology on the Orlando development well enabled a reduction in drilling waste handling and reduced downtime, due to the elimination of wait on weather, reducing rig non-productive time by allowing continuous drilling during adverse weather conditions. It also reduced handling, storage, offshore lifting and skip to shore vessel requirements, for the 17 ½" and 12 ½" sections, saving an estimated $640,000 in vessel costs alone (based on the market rates at that time).
Thorough planning meant initial challenges relating to delivery of equipment was quickly mitigated and support from TWMA, in close co-operation with AGR and the operator, helped to reduce the operational time-table and costs.
The drilling waste management operation was completed within time and on budget with zero Lost Time Incidents and zero loss of containment to the environment during operations.
Integrating Surface and Subsurface Models in an Automated Workflow Process for Asset Performance Analysis in Burgan Digital Oilfield –SEK
Authors: Rane Nitin , Al-Shammari Baraa , Desai Sameer , Al Sabea Salem , Pandey Mukul , Ibrahim Assem Mohammed , Chacko Rebin 
Published: November 2018

Abstract
Oil and gas companies face major challenges for meeting increased energy demands around the world. There is a sharp decline in production from existing fields and at the same time, discovery of large new fields has become increasingly difficult. As a result, oil and gas operators around the world are implementing various strategies to find ways of increasing recovery from existing reservoirs
With ultimate average recovery factor for oilfields on a worldwide basis of about 35%, companies are trying to improve recoveries through new technology initiatives such as integrated digital oil field approaches, which integrate reservoir and production system together for continuous monitoring of asset performance and production; optimization, and control of wells and fields.
Comprehensive workflows and collaboration environments are key elements of any successful digital oil field operation. They integrate a multitude of data sources and applications, capture the knowledge of production processes, and enable improved decisions. These workflows help overcome the complexity of today’s asset management operations.
Kuwait Oil Company implemented such initiatives in one of its assets in Burgan oilfield which involved instrumentation at well site, a SCADA system for data acquisition and control, integrated asset management workflows together with state-of the art collaboration center enabling faster diagnostics for well and facility performance. The integration of surface and subsurface models in an automated workflow process allows quick review of well health and assists in planning for short- and long-term production optimization actions.
Smart Hybrid Technology for Water Injector Wells: Installation, Commissioning and Data Interpretation Challenges - Case Study from a Middle Eastern Field
Authors: Rachapudi Ramarao Venata , Alshehhi Shamma , Saadwai Omar , Ayidinoglu Gokhan , Dodan Cornel , Khaled Moutaz Faysal , Quintero Fernando , Mubarak Saber , Gali Appala Raju , Mohammed Samy , Ikogho Brume 
Published: November 2018

Abstract
Effective reservoir management is critical to the success of water flood developments. Continuous monitoring of downhole parameters such as pressure, temperature and flow profile in water injector wells is vital in order to optimize the water-flood sweep efficiency and to avoid early water breakthrough in nearby oil producer wells. The target field has three stacked tight carbonate reservoirs with low reservoir energy and as such is being developed with water injection scheme from day one. As such, effective monitoring of downhole injection parameters is important from an early stage.
A common industry practice to monitor these parameters is to install Permanent Downhole Gauge (PDHG) and Distributed Temperature Sensing (DTS) system. Recently, a new smart Hybrid Technology has been developed to measure the downhole data at surface. This paper describes the successful application of this hybrid technology in a green onshore oil field development. Details are presented about the well bore segmentation design of the DTS system, the hybrid cable installation and the operational challenges with the hookup to the wellhead control system. The paper also presents the data acquired during commissioning job, and interpretation of the temperature data which was used to generate the injection profile along the wellbore. Finally, a strategy for future implementation of the DTS system is discussed.
Overall, this technology showcases the application of the smart hybrid completion for real-time monitoring of the water injection profile, including the pressure and rates along with injection volume per segment in the horizontal section. Real-time data from the hybrid technology has been integrated to digital oil field implementation to enhance the real time decision making to optimize the injection rates and to allow the operator to implement the decisions without any delay. This technology optimized the cables requirement and maximized the utilization of cable for multi-application environment to support acquiring Pressure, DTS and DAS data to generate real time injection profile.
Improving the Accuracy of Virtual Flow Metering and Back-Allocation through Machine Learning
Authors: Shoeibi Omrani Pejman , Dobrovolschi Iulian , Belfroid Stefan , Kronberger Peter , Munoz Esteban 
Published: November 2018

Abstract
In this study we have investigated a fully data-driven approach (artificial neural networks) for real-time back-allocation and virtual flow metering in oil and gas production wells. The main goal of this study is to develop computationally efficient data-driven models to determine the multiphase production rates of individual phases (gas and liquid) in wells using existing measured data in fields. The developed approach was tested on simulated and field data from several gas wells. Two different type of artificial neural networks (ANNs) were tested on simulated and field data to assess the accuracy of estimations for steady-state, transients and dynamics in productions due to cyclic operation (shut-ins and restart). The results showed that ANN was capable of accurately estimate the multiphase flow rates in both simulated and field data. The accuracy of the production rates estimation depends on the type of neural networks employed, production behavior (steady-state or transients) and uncertainties in data.