bluuebunny/crossref_metadata_2025_split huggingface dataset:
Iron Sulfide and Zinc Sulfide Inhibition and Scale Inhibitor Consumption
Authors: Alharbi Bader , Aljeaban Norah , Graham Alexander , Sorbie Kenneth S. 
Published: November 2019

Abstract
Iron sulfide (FeS) and zinc sulfide (ZnS) scales have been observed in many sour oil and gas wells. FeS often forms alongside other scales such as calcium carbonate and barium sulfate and such scales can be removed using chemicals like hydrochloric acid (HCl) and chelating agents. However, there are several drawbacks associated with the FeS removal by acid. For example, HCl acid, which outperforms other dissolvers has a high corrosion rate and generates hydrogen sulfide (H2S) gas as a byproduct. Other dissolvers, including chelating agents, often have low dissolution rates. Therefore, FeS inhibition is preferred as a strategy rather than allowing it to form followed by its removal.
The objective of this paper is to investigate the inhibition efficiency of various inhibitors for preventing FeS and ZnS deposition. Different scale inhibitor (SI) chemistries have been examined over a wide range of parameters, including temperature, salinity, pH and concentrations of Fe, Zn and sulfide. Static formation and inhibition experiments were conducted and the progress of the reaction was monitored by inductively coupled plasma (ICP) analysis and pH. In addition, the inhibitor consumption in sulfide scale solutions has also been investigated; i.e. the inhibitor concentration has been monitored during the sulfide inhibition process to determine the role and fate of the SI itself.
Polymeric scale inhibitors, including phosphino polycarboxylic acid (PPCA), showed a high inhibition efficiency for ZnS in different salinity and temperature conditions. On the other hand, some polymeric scale inhibitor that prevented the deposition of ZnS completely failed to inhibit FeS. It was found that, in mixed FeS and ZnS systems where both sulfide scales deposited, the precipitation of FeS had a negative impact on the inhibition efficiency for ZnS. By analogy, the FeS formation can affect the inhibition efficiency for other scales such as calcium carbonate and barium sulfate. In addition, in our SI consumption experiments we found that the scale inhibitor was consumed in ZnS solutions while there was no decrease (no SI consumption) in the scale inhibitor concentrations in FeS solutions.
Based on these results, we demonstrate that it is easier to inhibit ZnS rather than FeS under the same conditions. The presence of FeS had a negative impact on the performance of the scale inhibitor for ZnS and similar effects might occur in FeS/conventional scale systems. For the first time in a sulfide scaling system, this work examines if the scale inhibitor remains at its original dosage in solution or if it declines. There were two distinct behaviors, the scale inhibitor was consumed in ZnS but not in FeS solutions.
Contractor Certification Management System for Effective Project Handling
Authors: Abbas Zafar , Al Shehi Abdulla Ahmed 
Published: November 2019

Abstract
Engineering, procurement and construction (EPC) projects play an important role in oil and Gas & energy as well as petrochemicals & construction (civil) sectors not only for sustainable production but also to meet projected future demands. Therefore successful execution of projects is very important for industry. The paper discusse the proven sources of project delays at macro level. This paper furthers this discussion by introducing a unique mechanism of contractor certification management. This mechanism will oversee the contractor's performance and project delay's contributors. A mechanism to rate the contractors based on their performance will provide another tool to monitor contractors. Contrctactor certification management system might prove very successful mechanism that would help oranizations save their significant cost by timely excution of projects. This mechanism will provide a platform for contractors to compete with others, get high rating and receive significant appreciation.
Salt Creeping Effect on Borehole Collapse and Well Completion Design, Based on South Oman Field Experience
Authors: Moiseenkov Alexey , Smirnov Dmitrii , Mahajan Sandeep , Al Hadhrami Abdullah , Al Azizi Issa , Shabibi Hilal , Balushi Yousuf , Omairi Mahmood , Rashdi Mansoor 
Published: November 2019

Abstract
There have been many oil and gas field discoveries in the Cambrian Ara Group intra-salt carbonate rocks in the South Oman Salt Basin. These carbonates represent self-charging petroleum system with over-pressured hydrocarbon accumulation in dolomitized rock encased in the salt. Drilling and completion wells going through salt is challenging. Salt creeping behavior results in issues of stuck pipe during drilling operations, casings deformation and collapse that have led to well suspension and abandonment.
The full set of the available historical data analyzed to identify magnitude and history of the problem. The study conducted to estimate of salt creep magnitude, to assess the effect of the salt creep on cement quality, drilling and completion risks. The risk of salt creep on the drilling, completion and long-term well integrity was evaluated with multi-disciplinary integration of geological, geomechanical, petrophysical and well engineering aspects to minimize and mitigate the salt creeping risks. In addition to identify root cause for completion failure and providing recommendations to drilling practices, cementation and completion design that can improve well delivery process.
Salt creep behavior presents drilling challenges associated with excessive torque, stuck pipe, casing deformation, and poor cementing job. Salt creep associated risks to drilling and well integrity should be managed and mitigated. Key study findings captured for wells designs were: Salt creep rate increases with depth, salt thickness and differential stress (function of MW)Non uniform loading decreases the collapse rating of the casing and results in casing deformationNon-uniform loading likely due to poor cementing, interface between rigid carbonate intervals and salt, and irregular open hole quality.
Studied casing collapse cases could likely be attributed to several factors or combinations of factors such as salt mobility behavior, drilling with low MW, poor cement jobs and loss of internal hydrostatic support for the casing after cement job between liners lap. The improved multi-disciplinary understanding of salt creep is vital to reduce drilling and completion costs, unnecessary well abandonment and achieve good life cycle well integrity i.e. avoid extra side-track and workover cost due to integrity issues. The best practices and conclusions summarized in the study for drilling and completion design expected to benefit the exploration and development projects for the salt encased carbonate reservoirs around the globe.
Data-Driven Vs. Traditional Reservoir Numerical Models: A Case Study Comparison of Applicability, Practicality and Performance
Authors: Alatrach Yara , Saputelli Luigi , Narayanan Ram , Mohan Richard , Alklih Mohamad Yousef , Rubio Erismar 
Published: November 2019

Abstract
Efficient reservoir management is defined by its workflow structure stretching from a comprehensive integrated reservoir characterization (static and dynamic) to fast and reliable decision making for optimal field development planning. A lengthy and fragmented process that is scattered among multiple disciplines and data domains. The oil industry has made tremendous effort in advancing technologies to enable faster and smarter subsurface modeling, history matching, scenario prediction and risk analyses. Achieving optimality with reduced-risk requires typically prohibited high amount of human effort and technology resources.
As we enter into the Fourth Industrial Revolution of Big Data, Artificial Intelligence (AI) and Internet of Things (IOT) devices, alternatives complimentary tools to the conventional techniques have surfaced. The purpose of this work is to demonstrate the advantages and shortfalls of commercially available data-driven model techniques for dynamic reservoir forecast as compared to traditional numeric simulation techniques. In this paper, a consistent procedure to compare the performance of both data-driven models and full-physics numerical models is developed and discussed. The procedure was tested on an onshore reservoir located in Abu Dhabi, UAE that provided the basis and results for the analysis. The approach included analysis of human resources requirements, computer hardware, simulation performance and models updating strategy.
Design and Implementation Challenges for MLLD System
Authors: Kikuchi Shuichi , Fujita Kazuhiro , Nukanobu Gentaro 
Published: November 2019

Abstract
A water flooding pattern using maximum reservoir contact (MRC) wells will be utilized for the future developments of reservoirs in a giant brown field offshore Abu Dhabi. The increase in the reservoir contact together with the application of intelligent completion (IC) for the reservoir management is an effective way to improve the sweep efficiency, enhance oil production and minimize early water breakthrough. Meanwhile, the field is much congested with existing wells drilled from offshore well head towers and several artificial islands (AIs). In addition, many MRC horizontal wells have been and will be drilled in the overlaid reservoirs. Hence, well collision alarms are increasing day by day when planning a new well.
To meet with the field development perspectives as well as coping with such a critical field circumstance, unique well architectures with a multi-lateral IC, namely Multi-lateral Line Drive (MLLD) system are designed and the techno-economic analysis has been completed for specific cases.
This system will enable to reduce the overall drilling and completion cost for the field development with no adverse impact and mitigate the well collision risk by minimizing the number of mother wellbores penetrating through the overlaid reservoirs and provide real time monitoring and control to add values to the reservoir management.
This paper presents the drilling and completion strategy for the future reservoir developments, the MLLD system designs and associated technical challenges. In addition, outcomes from the case studies are addressed.
Improving Project Delivery Using Virtual Reality in Design Reviews —A Case Study
Authors: Ghadban Wassim , Kozina Vladan , Kelly Branwen 
Published: November 2019

Abstract
With the advent of the computerized 3D model environment, the engineering review process for complex process plants has improved dramatically, however, recent technological advances are facilitating the next step in productivity.
Typically, engineering companies conduct design reviews using a multidisciplinary panel of seasoned engineering experts to assess the safety and the utility of the design. The review is based upon a combination of traditional paper-based deliverables and on-screen views of the 3D model using conventional software tools, e.g. SP3D, PDMS and PDS. The Operations function is often not represented in the review phase at this early stage in the lifecycle of the asset.
By conducting two separate design review exercises, first using the conventional design review method followed by a review built around virtual reality (VR) immersion, we were able to demonstrate incremental benefits possible through the incorporation of VR technology. The identified benefits fell into two main categories, specifically identification of design deficiencies that: were not observable using traditional design review methodswere overlooked by the traditional panel of expert reviewers
Using VR technology, the immersive model review was provided in an intuitive format which allowed deeper understanding of the spatial context and allowed a more diverse team of field operatives and maintenance personnel to participate. The final design outcome was improved by the addition of practical insights from operations stakeholders who would otherwise have been excluded from the design review process.
Ultimately, the combination of improved spatial understanding and greater diversity of inputs led to a client-certified savings of USD$2.55M in future modifications and reworks.
Middle East Steamflood Field Optimization Demonstration Project
Authors: Behm Ed , Al Asimi Mohammed , Al Maskari Sara , Juna Wladimir , Klie Hector , Le Duc , Lutidze Giorgiy , Rastegar Reza , Reynolds Albert , Tathed Vinit , Younis Rami , Zhang Yuchen 
Published: November 2019

Abstract
Occidental Mukhaizna completed a steamflood field optimization demonstration project involving about 100 Mukhaizna wells from Mid-December 2018 to Mid-March 2019.
The field demonstration involves a data analytics process that provides recommendations on the best steam injection allocation among wells in order to improve overall steamflood performance. The process uses a low fidelity physics-based proxy model and cloud-based parallel processing. A field optimization engineer history matches and anchors a proxy model to current well and field operating constraints. The engineer completes hundreds of forward runs as part of an optimization algorithm to identify scenarios most likely to help increase value (oil production per steam injected) over the short term in the field, while honoring all producing and injection well operating ranges. The reservoir management team vets the rate change ideas generated and provides their recommendations for changes so the likely best and most practical overall scenario is implemented. The process is refreshed monthly so field performance results are included immediately, and the optimization process is kept evergreen. The field results so far have been encouraging, yielding an increase in oil production that has exceeded expectations.
This paper will describe the data analytics field optimization process and workflow, present the baseline performance versus field demonstration results, and share lessons learned.
Challenges in Design of Wellfluid H2S Mitigation on an Offshore Wellhead Platform - A Case Study
Authors: Subramanian Senthilkumar , Singh Harendra , Kamal Faris Ragheb , Takieddine Oussama 
Published: November 2019

Abstract
Hydrogen Sulfide (H2S) occurs naturally in well fluid and imposes variety of challenges in oil and gas industry. Although there are many methods that may be employed to remove H2S from gas and liquid streams, selection of technology, design, installation & operation on a remote unmanned wellhead platform offers unique challenges. This paper presents NPCC’s experiences in implementation of H2S mitigation unit on a recent offshore well head platform project.
Offshore wellhead platforms are designed to minimize manning frequency and duration of stay. Further, climatic conditions - heavy rains during monsoon impose additional challenges to logistics, restricting movement of crew members, service boat requirements to replenish consumables on unmanned wellhead platform. Therefore, it’s preferred to select wellfluid H2S mitigation unit requiring minimal operational intervention. Sweetening of multi-phase wellfluids (mixture of oil, gas & produced water) can be performed by direct injection of scavenger chemicals but pose problems in downstream facilities. Alternately, it was proposed to separate the wellfluid into gas & liquid streams and treat them independently for H2S removal.
Experience demonstrates that proper selection and application of proven technology are critical for wellfluid H2S mitigation. Based on assessment of various technologies, the most optimized approach for this case is use of a solid based scavenger media packed in an Adsorber vessel to treat the associated gases and a triazine based liquid scavenger to treat the separated liquids. Adsorber vessel needs to be designed considering replacement of spent media with fresh solid scavenger based on worst possible monsoon period in the region. The important design challenges include unloading of spent media and loading of fresh media into the Adsorber vessel. This involves establishing logistics in transporting fresh media to offshore and sending spent media to onshore for safe disposal. Safe land disposal practices are recommended to meet the local environmental regulations.
H2S removal provides distinct advantages and focus is now shifting towards removal at wellheads due to potential high returns on investment in current oil market. Adding new sour wells to existing production may pose limitations in downstream facilities such as existing pipeline and process complex. It is worth to consider sweetening of wellfluid at wellhead platform thus mitigating H2S at the source itself instead of augmenting existing sweetening system at downstream facility.
This paper discusses a case study based on an actual project, highlighting the design challenges and experience gained during execution of wellfluid sweetening system on a remote wellhead platform, thus providing economic benefit to all stakeholders.
Successful Drilling and Completion of a Short Radius Deep Gas Re-Entry Well Towards the Minimum Stress Direction
Authors: Almusallam Ali , Yahya Hany , Ab Hamid Abdul Halim , BinAli Ali 
Published: November 2019

Abstract
Since the foundation of the oil industry, many wells were drilled with an old design. Such wells had been limiting the reserve recovery potential. In extreme cases, some of these wells had been suspended and remedial work is now required to unlock the wells’ potential. This paper presents a case study for restoring production and increasing the salvage value of suspended wells in areas with proven production potential yet declining production yields.
Challenges for drilling the well were found in three key areas: Sidetrack Points: The main concern in this well was the failed cement job in the 9-5/8 in. casing and the pressurized formation above the targeted reservoir that had the potential to create new fluid paths through cement channels. The pressurized formation required a very heavy mud weight of 152 pcf and managed pressure drilling (MPD) to drill the previous well and incurred losses at the same time. By increasing the depth of the sidetrack point and drilling a short radius 5-7/8 in. wellbore in less than 200 ft., the risk of the pressurized formation communicating to the new lateral was eliminated. This saved the cost of drilling two hole sizes and the cost of milling approximately 1,500 ft. of existing 7 in. liner and running a new one as illustrated in Fig-1.Geomechanical Challenge and Petrophysical Demands: Due to fracturing needs, drilling toward a minimum stress direction was required even though this was not preferable from a drilling standpoint. The stuck pipe tendency becomes greater when compared with drilling toward the maximum stress direction in deep wells. Placing the well in high porosity zones required real-time geosteering using high-end logging while drilling (LWD) services in high dogleg environments. By using LWD technology with high bend rates, the required reservoir contact was achieved by drilling less footage than planned. Modified best practices played a major role in achieving these objectives.Running the Liner through the High DLS (Dogleg Severity) Environment: Drilling the short radius resulted in an averaged DLS of 30 deg/100 ft where it also reached a maximum 53 deg/100 ft across some intervals. Due to a high build rate and the azimuthal change required to reach the target. The use of oil base mud and bridging materials along with constant monitoring of mud rheology allowed the liner to be deployed successfully through high DLS section. The plan for centralizers was also modified to reduce liner stiffness while still obtaining isolation from the water bearing reservoir above the target.
The success in delivering the well and returning it to production after a challenging workover job opens the door for future activity. Restoring wells by employing the short radius drilling technique provides a cost effective solution compared to conventional workover methods in many cases.
Implementing a Successful Risk Based Inspection Program
Authors: Ali Asad , Sabry Houssam 
Published: November 2019

Abstract
Production of Oil, Gas and Petrochemical from production units is becoming very competitive every day. As products are sold in open market, production cost drives an organization's profitability. To keep a plant available for production as much as possible, Asset Performance Management (APM) or Asset Integrity Management (AIM)is the key. Risk based inspection (RBI) is a decision making tool that deals with integrity management of static equipment and piping through focus on prioritizing inspection based on the risk.
Review of published guidelines for RBI such as API RP 580/581, ASME PCC3, DNV-RP-G101, EN 16991 etc., suggests that they provide either oversimplified or complex explanations which makes it difficult for beginners to grasp all the aspects that are critical for a successful RBI project. Therefore, this paper is aimed to provide and discuss the essential elements for effective RBI implementation project in a simplified way. RBI project can be divided into four major phases i.e project initiation and pre-requisites, workshops & trainings, RBI analysis phase and post RBI actions. Each of these stages is discussed with details in this paper.
An overview of successful RBI program used within the industry and from the ADNOC LNG RBI implementation experience, is provided with details. Project management approach for RBI program implementation is conveyed by dividing project into different phases and highlighting the inputs/outputs and activities for each phase. Objectives, time and resources such as data and personnel required, software features that are essential, project planning and monitoring are provided.
RBI program implemented efficiently in accordance with suggested plan, results in an overall optimization of inspection for static equipment/piping while maintaining their integrity as part of a broader APM or AIM strategy.
Ranking Shale Performance from Water Flowback Analysis, Field Case
Authors: Ibrahim Ahmed Farid , Assem Ahmed , Ibrahim Mazher , Pieprzica Chester 
Published: November 2019

Abstract
In recent years, in unconventional reservoirs, main fracture parameters including fracture permeability and fracture volume can be early evaluated using flowback data analysis. For analysis purposes, diagnostic plots, straight-line methods, and simulation model history-matching techniques are utilized. Usually, immediate gas and water production occur during flowback in shale gas wells.
In this paper, solution of water diffusivity equation for different flow regimes during the early time of well life was used to analyze water performance. These flow regimes were determined based on the diagnostic plot of water rate vs. time. The analysis from Water RTA was used to calculate initial water in place (OWIP) and fracture parameters. The difference between the OWIP and the injected fracturing fluid was correlated against the formation water saturation.
The main conclusions from this analysis are; 1) High quality shale if the OWIP equal to the total injected water volume, and water-production data usually do not show the transient period and in some cases, boundary dominated flow (BDF) is present. 2) Low quality shale if the OWIP is greater than the total injected fracture fluid volume, and transient flow regimes are expected. High quality shale is good candidate for soaking process. The well performance increases after soaking process in the case of low formation water comparing to the high-water saturation wells.
Honoring the flowback data can help to estimate the fracture geometry and indicate the quality of the shale formation.