bluuebunny/crossref_metadata_2025_split huggingface dataset:
Design for Reliability: Purpose Driven Sand Control Methods for Cased and Perforated Wells
Authors: Soroush Mohammad , Roostaei Morteza , Mohammadtabar Mohammad , Hosseini Seyed Abolhassan , Mahmoudi Mahdi , Sadrzadeh Mohtada , Ghalambor Ali , Fattahpour Vahidoddin 
Published: October 2020

Abstract
The historical challenges and high failure rate of using standalone screen in cased and perforated wellbores pushed several operators to consider cased hole gravel packing or frac-packing as the completion of the choice. Despite the reliability of these options, they are more expensive than standalone screen completion. Since several developments are not designed for cased hole gravel pack or frac-pack, purpose-driven sand control methods for cased and perforated wells are recommended.
This paper employs a combined physical lab testing and Computational Fluid Dynamics (CFD) for lab scale and field scale to assess the potential use of the standalone screen in completing the cased and perforated wells. The aim is to design a fit-to-purpose sand control method in cased and perforated wells and provide guidelines in perforation strategy and investigate screen and perforation characteristics. More specifically, the simultaneous effect of screen and perforation parameters, near wellbore conditions on pressure distribution and pressure drop are investigated in detail.
A common mistake in completion operation is to separately focus on the design of the screen based on the reservoir sand print and design of the perforation. If sand control deemed to be required, the perforation strategy and design must go hand in hand with sand control design. Several experiments and simulation models were designed to better understand the role of perforation density, the fill-up of annular gap between the casing and screen, perforation collapse and screen plugging on pressure drop. The experiments consisted of a series of step rate tests to investigate the role of fluid rate on pressure drop and sand production. There is a critical rate in which the sand filled annular gap will fluidize and also sanding would be different for different fluid density. Both test results and CFD simulation scenarios comparatively allow to establish the relation between wellbore pressure drop with screen and perforation parameters and determine the optimized design.
The results of this study highlight the workflow to optimize the standalone screen design for the application in cased and perforated completion. The proper design of standalone screen and perforation parameters allows maintaining cost-effective well productivity. Results of this work could be used for choosing the proper sand control and perforation strategy, rather than using gravel packing and frac-packing methods in cased and perforated completions.
Redefining Technical Limit Managed Pressure Directional Drilling Solution in Depleted South Texas Lessons & Best Practices From 5 Wells
Authors: Oliver John , Ngan Alex , Arnone Maurizio , Valecillos Juan , Stich Chad 
Published: October 2020

Abstract
This paper will discuss the Managed Pressure Directional Drilling fit-for-purpose solution deployed to meet the drilling challenges faced in 5 consecutive wells drilled in South Texas, USA. This innovative solution integrates a state-of-art Rotary Steerable System (RSS) with Managed Pressure Drilling (MPD) technology. Drilling hazards such as well control events, simultaneous kick-loss, and stuck pipe were mitigated, and an improved drilling performance with a reduction of NPT as compared to other directional drilling systems.
The solution requires the integration of two highly technical disciplines, MPD and Directional Drilling. Hence, a Joint Operating & Reporting Procedure (JORP) and a defined communication protocol are crucial for effective execution. The solution is based on a rigorous Drilling Engineering process, including detailed offset wells analysis to deliver a comprehensive risk assessment & mitigation plan in collaboration with the Operator to tackle drilling hazards without compromising the directional drilling requirements.
This paper will summarize the 5 wells operations, the drilling optimization results, and the lessons learned from an integrated services point of view in terms of deliverables that made the difference on this project and allowed the Operator to achieve their objectives. In particular, the effective communication protocol between the directional drilling services, MPD services, and rig contractors to ensure safe operational alignment.
RFID Control Valve Leading to Digitalization of Plant
Authors: Khan A. 
Published: October 2020

Abstract
A radio frequency identification (RFID) tag can be used to identify and track objects wirelessly through electromagnetic fields. Application in today's markets include logistics and goods tracking. An innovative way to use RFID could be integration with control valves at plants, leading toward digitalization of the plant and IR4.0.
RFID enabled control valves, integrated with IR4.0, can give a holistic view of control valves across the plant. In this case, an RFID tag could be attached to a Smart Control Valve Head, acting as a controller and actuator. Any alarm or malfunction could be reported through the Smart Control Valve Head to a central control system. A web-based solution could be added in layers, which enables the notification to of appropriate workgroups. It can also enable improved preventive maintenance.
The solution will be based on a wireless identification and sensing platform (WISP), which will use the concept of RF Energy Harvesting using RFID with a rectenna — a combination of antenna and rectifier. An antenna is used to collect ambient RF energy, which is available around us in the form of electromagnetic waves from mobile phones and wireless networks. A rectifier converts the RF energy into electricity for powering up RFID, thereby offering a wireless and battery-less RFID solution. A RFID tag connected to the Smart Control Valve Head will form a localized control loop with wireless communication to the central control system for data sharing and smart analytics.
The proposed concept of RF energy harvesting using a rectenna with an RFID-enabled control valve can lead toward the possibility of a decentralized wirelessly controlled valve, digitalization of plants with superior maintenance, and a new paradigm of IR4.0.
Assurance of the Asset Action Plan: A Strategic Endeavor Toward a Credible and Reliable Forecast
Authors: Al-Ghnemi Mohammad , Kumar Ashish , Mendjoge Ashish , Bora Anup , Chandan Thakuria , Al-Najdi Ali , Al-Bahar Mohammad 
Published: October 2020

Abstract
Oil companies are facing several challenges from external and internal environment like volatility of crude oil price, capex reduction, subsurface uncertainty, delay in the surface facilities etc. that impacts the long-term strategic plans. Kuwait Oil Company (KOC)'s annual Asset Action Plan (AAP) operationalizes the long-term strategy of the company assurance of annual AAP is key for having a credible forecast and meeting long term goals. A robust Corporate Assurance process has been developed that consists of workflows that will guarantee company's ability to develop and execute credible field development plans. A review on proper planning, execution and alignment of different business processes is required during assurance of Asset Action Plan. This assurance process provides confidence to the management in approving the AAP.
Opportunity based Asset Action Plan (AAP) process is the backbone of KOC's annual business planning and portfolio management system. This allows alternative portfolio choices and management can make the right decision. The opportunity will provide consistency and clarity of the Portfolio constituents and common rational basis for investment decision making and allow for alignment between the KOC major business processes.
AAP process is carried out annually and is initiated through high level business guidelines management. During finalization of AAP, an assurance review by corporate technical team for large national companies having multiple assets is considered as best practices that support management in approving the AAP and to steer the company in right direction.
AAP Assurance process involves reviewing the forecast with the historical performance of the reservoir, planned activities, expected outcomes from the activities, feasibility and associated cost. A systematic three stage process has been adopted to conduct AAP Assurance for reservoirs which are at different phases of development.
This assurance workflow and methodology helps to align changing oil and gas scenarios, different business process, health of the reservoirs and meeting future production targets.
This process ensures that proposed AAP plan will be able to deliver production target commitments and identify any gaps and propose mitigation plans. This also confirms that ongoing development plans are in alignment with facility planning. It also validates conformance of the adopted reservoir development and management workflows with global best practices (analogue reservoirs) to maximize recovery and maintaining health of reservoir.
Fruit Extracts as Natural, Green, Non-Toxic Corrosion Inhibitors
Authors: Ng Jun Hong , Almubarak Tariq , Nasr-El-Din Hisham A. 
Published: October 2020

Abstract
Corrosion inhibitors currently used in the oil and gas industry are associated with environmental concerns and severe health risks. Recent advancements in corrosion inhibition technology had successfully tackled environmental concerns, but still faces issues with toxicity and performance at high temperatures. This work aims to develop environmentally friendly and non-toxic corrosion inhibitors that can overcome these limitations. Extracts of 14 common fruits were tested as sources of potential corrosion inhibitors.
In order to determine the inhibition effectiveness of the different fruits, N-80 coupons were exposed to 15 wt.% HCl solutions at temperatures between 77-250 °F with 0.2-2 wt.% of dried ground fruit for 6 hours. In addition, a control solution containing no corrosion inhibitor was used to establish a corrosion rate for a base case. Upon identifying high performing dried ground fruits, extracts of these fruits were subsequently tested to save cost by minimizing quantity needed while achieving acceptable performance.
At a concentration of 2 wt.%, fruits 1 and 2 were found to perform the best, exhibiting more than 98% corrosion inhibition efficiency at 77°F. Fruits 11 and 12 were observed to perform the worst, going so far as to enhance corrosion on the coupons. At 150°F, the corrosion rate of fruit extract 1 was 0.00436 lb/ft2, while that of fruit extract 2 was 0.0277 lb/ft2. At 200°F, the addition of a corrosion inhibitor intensifier resulted in a corrosion rate of 0.00130 lb/ft2 for fruit extract 1 and 0.0173 lb/ft2 for fruit extract 2. At 250°F, a second corrosion inhibitor intensifier was used. The resulting corrosion rate was 0.0320 lb/ft2 for fruit extract 1 and 0.00963 lb/ft2 for fruit extract 2. These results show that a naturally occurring, green, non-toxic corrosion inhibitor can be developed from these fruits and can comfortably pass the industry requirement of achieving corrosion rates below 0.05 lb/ft2 for low carbon steel tubulars.
Corrosion during acid treatments causes destruction to the tubulars and downhole equipment. Consequently, this leads to an increase in expenditure to maintain well production rates and well integrity. Therefore, corrosion inhibitors must be included in any acid treatment formulation. The results in this work share two new naturally occurring, green, non-toxic, high-temperature stable corrosion inhibitors that can be developed from fruits and can successfully protect the tubular during acid treatments.
Phase Behavior Modeling of Acid-Gas Aqueous Systems CO2, H2S, CH4, Water and In-Situ pH Measurements in Applications to Wellbore Integrity and Top-of-Line Corrosion
Authors: Dindoruk Birol , Ratnakar Ram R. , Suchismita Sanyal 
Published: October 2020

Abstract
We present thermodynamic modeling and pH measurements of fluid systems containing acid-gases (e.g. CO2 and H2S), water and hydrocarbons – replicating the production and shutdown conditions in sour fields – for the purpose of evaluating top-of-line corrosion and wellbore integrity, and screening/selection of the proper wellbore materials. In particular:
An EOS model using Peng-Robinson EOS in combination with Huron-Vidal mixing rule for aqueous sub-system is developed. In the model, subject EOS parameters are calibrated against existing thermodynamic data (saturation data for pure components and solubility data for binary systems) in literature. A new in-situ pH measurement data is presented for a model system corresponding to sour field. It was found that the wellbore can be subjected to pH levels as low as 2.7 with reservoir fluid containing 12 mol% CO2 and 88 mol% methane with downhole flowing conditions of 200 bar and 150°C, and wellhead shut-in conditions of 300 bar and 4°C, as observed from the experiments. A modeling workflow is developed to estimate pH of the condensed water as a function of temperature and composition of the aqueous phase. The comparison between prediction and experimental measurement show very good match between the two (within pH ±0.1).
Such studies (pH measurements and prediction) are not available in literature but play important role in material screening and assuring wellbore integrity for sour fields. More importantly, sensitivity analysis can be performed to investigate the effects of various factors (such as reservoir temperature/pressure, shutdown conditions, and compositions or extent of souring) on pH prediction. Furthermore, the methodologies developed through this work can also be extended to reservoir facilities, pipelines, sour gas disposal/handling units, as well as, downstream systems such as as water-utilities, reactor plants and refineries. The work can also support for regulation/licensing for these sour systems.
The Effect of Margin and Reserves/Production Ratio on Oil and Gas Transaction Multiples
Authors: Gajdica Ronald , Byrne Randall 
Published: October 2020

Abstract
Precedent transaction multiples are often used to estimate the market value of oil and gas assets. The multiples typically used for valuation include production, reserves, and cash flow multiples. Improper application of these multiples can lead to valuation estimates that are significantly different than actual market value. This paper outlines a method to improve the accuracy of market value estimates from multiples analysis by incorporating (1) the correlation between multiples and proved reserves to production ("R/P") ratio, and (2) the effect of profit margin ("margin") on transaction multiples. The effect of margin is especially relevant because some transaction metrics are not necessarily valid in the current market due to significant changes in commodity prices.
Economic runs for a variety of conditions were made to observe the theoretical effect of R/P ratio, margin, and discount rate on net present value. The net present value at a 10% discount factor ("PV10") was used as a proxy for market value. Then, production, reserves, and cash flow multiples were calculated and analyzed. Relationships between the different variables were studied, and equations to calculate the various multiples as a function of R/P, margin, and discount rate were constructed. Comparison of multiples generated from discounted cash flow ("DCF") regression analysis to actual transaction data show that the shapes of the various curves generated agree with the historical trends.
This paper also includes commentary on how to correctly apply the multiples to asset valuation, equations to calculate the various multiples, and a discussion of pitfalls to avoid when performing multiples analysis.
Successful Installation of a Down-Hole Fiber Optic Wetmate Connection System
Authors: Samuelson Marc , Harris Shane , Schrader Kirby , Mendez Luis 
Published: October 2020

Abstract
In July and again in September 2019, six-fiber downhole fiber optic wet-mate connections were successfully landed on fiber enabled lower completions, "lighting up" the completion from the wellhead to the reservoir. The tools that enable this technology must simultaneously align six fibers the diameter of a human hair end-to-end in a downhole environment.
These deployments are the first successful installations of fiber optic downhole wet connects in the North Sea and it represents a step change in the information that can be obtained from permanently installed sensors at the reservoir in a multi-trip completion. To date, opportunities for fiber optic sensing have been quite limited in multi-trip completion systems. This has restricted the use of many fiber optic technologies to the upper completion rather than where it can provide the most impactful data - at the reservoir.
This paper will present a brief history of the development and validation of this fiber optic connector system design including specific qualification testing for these North Sea wells. The fiber optic downhole wet-mate connector is a result of more than a decade of engineering design, testing and qualification. Further refinements were made with this specific group of wells in mind, and the system was optimized, assessed and tested with support from the operator. A close working relationship between the operator and the service company enabled optimization of the tools as well as the entire completion to reduce the risk of NPT and infant mortality of the equipment.
The operations resulted in a successful connection of all six fibers and a fiber optic instrumented lower completion with full well surveillance capability. Six individual fibers were connected simultaneously, enabling sensing of distributed temperature, distributed acoustics, and two pressure/temperature gauges on the exterior of the lower completion with direct contact to the reservoir. Optical losses across the connector were less than 0.5 dB for all fibers.
This fiber enabled completion allows the completions and reservoir engineers to gather and interpret the distributed data that obtained by the interrogators from the interaction of the optical fiber and its surrounding environment.
Large Scale Subsurface and Surface Integrated Asset Modeling - Lessons Learned
Authors: Hafez Hafez , Saputelli Luigi , Mata Carlos , Mogensen Kristian , Di Sarria Andrea , Singh Nicholas , Mohan Richard , Escorcia Alvaro , Pires Joshua , Asarpota Jyotsna , Ge Haoyou , Hernandez Cristina , Bansal Yogesh , Rodriguez Jose 
Published: October 2020

Abstract
Implementing large-scale projects within a company are challenging tasks and often provide a good learning curve that can be beneficial to understand the complexity of the work involved. An integrated subsurface to surface asset modeling solution was implemented at the country level to automate production capacity planning while optimizing shortfall and opportunity identification (Hafez et al., 2018).
Several structured business processes support the developed system; it orchestrates the analytical processes followed by the corresponding approval system. A robust data management process was implemented and backed with a business process that includes more than 150 configurable exception rules. Besides, the developed solution leverages the rigor of the first principle and data-driven models to provide a desired and stable outcome ranging from potential evaluation, quota definition, capacity management, business plan validation, and other business processes. The developed solution can isolate wells, sectors, reservoirs, and/or fields for further evaluation. Given the challenge of balancing market demand with profits and subsurface deliverability, a time-efficient, balanced, and integrated solution is expected to provide an edge to an organization in this competitive environment.
The Integrated Capacity Model (ICM) system has already been utilized for capacity and deliverability of 2019 and 2020 ADNOC business plans demonstrating 99% agreement with field capacity tests. The system shown +3% profit gains through various production optimization scenarios, while recommending which assets, fields, and/or reservoirs can be targeted to achieve those targets.
Developing and implementing the solution at such a large scale surfaced various challenges at organizational, infrastructure, and solutions/workflows. This paper discusses those challenges and the ‘lessons’ learned during the implementation of this solution. Various value-added use cases are presented.
Production Enhancement In Subsea Fields Through Using Intelligent Completion
Authors: Taher Shetia Mohamed ahmed , selim Islam Elsayed 
Published: October 2020

Abstract
This paper shares The Delta Deep Marine (DDM) experience in developing stacked reservoirs subsea fields by implementing smart completion for reservoir management, surveillance & production sustainability.
Smart well system are composed of permanent downhole sensors & downhole flow control valves that allow recording, evaluating, & actively managing production in real time remotely without any well interventions, which facilitate to improve reservoir management strategy. Once a smart well is completed, valves can independently control each zone of the well, such as controlling zone production when it starts producing water, shutting water-flooded zones or in defensive mode, avoid sand production by adjusting of smart valves settings to safe guard against losing the well.
This paper contains different case studies in applying smart completion & their positive effects in the field development plans. The benefits of optimal application of smart well completion technology in DDM are numerous. These include reducing number of development wells so reduce CAPEX, developing marginal opportunities to improve economics, avoiding well intervention for zonal control to reduce the OPEX, reducing water production to improve subsea network efficiency & reduce water-handling issues, reducing geological uncertainty by proper frequent zonal test, reducing risk of losing the well by control each zone independently to avoid sanding, managing commingled reservoirs with different characterization properly & maximizing reserves. In addition to auto gas lift oil zones without a need to subsea artificial lift infrastructure that allows completing oil zones as an upside gain.
Smart completion was identified as the best option to meet deepwater requirements in producing this field with minimum number of wells without sacrificing targeted production profiles.