bluuebunny/crossref_metadata_2025_split huggingface dataset:
Addressing the Current Practice of Over Estimation of Structural Resistance of Existing Strengthned Structure.
Authors: Sharma Madhugiri Shashi , Patel Pareshkumar , Omar Tarek , Sarkar Anjan , Atia Mohamed 
Published: November 2020

Abstract
Present regional practices for performing a conventional offshore structural analysis erroneously considers strengthening proposed for any additional loads on existing structures to also support the already existing loads which mainly is due to the limitations of the linear analysis approach presently adopted. This method could lead to false perception of code compliance exposing strengthened structures to a higher failure risk. The paper introduces a more accurate approach for the assessment of the structure and the evaluation of the effectiveness of strengthening introduced at different stages through the structure’s lifetime.
Through the course of this study, a comparison was carried out between the conventional linear strength analysis vis-a-vis the non-linear finite element analysis technique for a typical offsore structural Bridge. The work involved full simulation of a bridge supported by two offshore structures using the conventional method and assessing the results. Subsequently an integrated finite element model, with critical locations represented through 4-node shell elements was generated. A non-linear finite element analysis was adopted where stage-wise strengthening and load history was simulated.
The structural assessment using the non-linear finite element analysis technique has demonstrated that the bridge did not comply with the structural strength requirements of ISO 19902 international standards in as-is condition. This was in contradiction to the conclusion and outcome of the previous design reports. The previous strengthening design had adopted the conventional linear design methods, ignoring the realistic effects of loading and strengthening stages throughout the history of the structure. Ignoring these effects had misled to the perception of effectiveness of the new combined sections, whereas accurate representation had demonstrated that only the new additional loading is distributed to the new combined section and the existing loading is resisted by original sections only. This behavior is applicable if the installation techniques did not include jacking systems to relieve the loading prior to strengthening.
The results and conclusions of the study have given an insight to the limitation of the conventional linear structural analysis methods in capturing the accurate structural behavior. It also provided a demonstration of how an incompatible type of assessment may lead to incorrect perception of compliance.
Interpretation of Mini-Frac and Flowback Pressure Response: Application to Unconventional Reservoirs in the UAE
Authors: Alhashmi Omar , Eker Ilkay , Kazemi Hossein 
Published: November 2020

AbstractThe main objective of the research presented in this paper was to develop a working knowledge of the unconventional shale in the UAE Diyab formation which includes reservoir engineering evaluation of the UAE Diyab Upper Jurassic gas condensate and Shilaif Middle Cretaceous light oil shale development. To achieve this objective, (1) we measured core permeability of a couple of Diyab cores with and without fractures, (2) we analyzed the pressure fall-off data from a Diagnostic Fracture Injection Test (DFIT) to determine in-situ matrix permeability for use in reservoir evaluation, modeling, and forecasting reservoir performance, and (3) we determined the effective permeability (that is, combined permeability of matrix and microfractures) of a Diyab stimulated well using rate transient analysis (RTA). Furthermore, we put together both analytical and numerical models for single-phase and two-phase flows in support of the interpretation of the field pressure falloff DFIT data, and the data from a laboratory DFIT conducted in a granite core by Frash in 2014 to shed light on enhanced geothermal reservoirs. Finally, we calculated the depths of filtrate invasion and the cooled region surrounding the hydraulic fracture surfaces to determine the net stress change near the surface of hydraulic fractures, which is commonly referred to as the ‘stress shadow' effect.We concluded that our research effort was both informative and instructive in determining the effectiveness of the stimulation efforts for the wells used in this study, and the process can be similarly utilized in any shale stimulation effort elsewhere.
Recent Advances in Waterless Fracturing Fluids: A Review
Authors: Almubarak Majed , Almubarak Tariq , Ng Jun Hong , Hernandez Julio , Nasr-El-Din Hisham 
Published: November 2020

Abstract
Hydraulic fracturing technology has grown popular with the rapidly increasing development of tight conventional and unconventional reservoirs. A major concern with this technique is the use of large amounts of water in these treatments. The use of water causes many potential damaging issues in the formation and limits the amount that can be saved for future generations. One solution is waterless fracturing treatments, which were developed to reduce or eliminate the need for water in hydraulic fracturing.
Hydraulic fracturing treatments consume at least 200,000 gallons of water in conventional wells and up to 16,000,000 gallons of water in unconventional wells. The pumped water must include clay stabilizers to deal with the sensitive clays in the formation. Additionally, using water poses a risk of inorganic scale precipitation near the wellbore. Water can also cause severe emulsions that can lead to emulsion blockage cases. Moreover, there are significant reports of water blockage cases in tight gas wells. Only a mere 10-30% of pumped water flows back after the treatment, with the rest attached to clays, or stuck in the pores due to high capillary pressures. Water-based fluids can also cause alterations to relative permeability, and liquid holdup cases in many gas wells. These issues can certainly increase near wellbore skin and reduce production rates. At the end of the treatment, water still causes issues related to disposal and separation prior to diverting it to the plant.
The main challenges in developing waterless fluids include feasibility, environmental friendliness, and effectiveness to stimulate the reservoir. This review will cover the various waterless fracturing methods such as hydrocarbon-based, liquid CO2, energized, and foamed fluids (CO2 and N2 foams) as well as their advantages and disadvantages. Studies into the properties of these fluids, such as rheology, solubility, compatibility, will also be discussed. Field trials will be examined where applicable.
This literature review examines various waterless alternatives to traditional fluids for hydraulic fracturing. From this paper, readers can better understand the nature of waterless technologies and be able to better evaluate these technologies for fracturing purposes.
Sour Gas Has A Sweeter Future - Bulk H2S Removal Using Polymeric Cellulose Triacetate Based Membranes
Authors: Sanghani Pinkesh , Kumar Hans , Ghorbani Nasser , Morisato Atsushi , Mahley George 
Published: November 2020

Abstract
Approximately 40% of current global natural gas resources have high H2S and CO2 concentrations. The H2S concentration in Middle East gas reservoirs can potentially reach up to 30 mol%. H2S is toxic; therefore, the produced natural gas must be treated and sweetened. In this high H2S environment, a membrane technology that can remove the bulk of H2S from produced natural gas will reduce the load on the amine treatment and sulfur recovery unit operations downstream in gas processing facilities. Bulk removal of acid gases with membrane technology will lower SO2 emissions through a reduction in flaring, elemental sulfur production from sulfur recovery units, and reduce unit delivery costs for the life of the field.
Since 1984, Schlumberger has deployed cellulose triacetate polymeric membranes for CO2 removal in gas processing and EOR applications. In collaboration with a major oil and gas exploration and production company, our membrane science research team is testing cellulose tri-acetate acid gas removal membranes to characterize separation performance under a variety of process conditions. The team deployed a pilot system capable of testing gas with 25% H2S in the USA. These membranes will separate both acid gas components, CO2, and H2S from the feed gas and retain hydrocarbons in the residue gas sent to the amine system for further processing. Low-pressure acid gas permeate can be reinjected into the reservoir for enhanced oil recovery or sequestration.
Initial laboratory testing and predictive modeling of the membranes, completed with an American academic research institution, have shown promising results for bulk H2S removal. Pilot system testing data will further de-risk and validate the feasibility of technology deployment and facilitate economic modeling of this technology's business impact. We will present the results of the testing to date which will form the basis of the observations and conclusions of the paper.
This paper will also present a case study to show the business impact of deploying a hybrid system (membranes + amine) in comparison to a conventional amine system.
After testing, operators will have satisfactory information available to review alternative processing facility concepts and re-evaluate the economics of ultra-sour gas field development projects.
Novel Machine Learning Approach to Forecast Reviving Unconventional Oil Reservoir Production
Authors: Ursegov Stanislav , Zakharian Armen , Taraskin Evgenii 
Published: November 2020

Abstract
For many unconventional reservoirs, the initial oil saturation is extremely low (around 30 %). In such circumstances, it is necessary to use alternative geological and hydrodynamic simulators to forecast production levels. A novel adaptive modeling approach based on cascades of fuzzy logic matrices was proposed and implemented for a mature carbonate oil reservoir in the Permian basin of Texas where next generation waterflooding was considered to revive development process and increase oil recovery.
The proposed approach is a variant of machine learning to solve the classical analysis and synthesis problem. At the analysis stage, the input and target parameters are normalized in order to equalize their significance. For each pair of input parameters, a fuzzy-logic matrix is formed and populated with actual values of the target parameter. The set of matrices forms a cascade in which every component is characterized by its own membership function. At the synthesis stage, forecasted results of the target parameter are calculated taking into account all membership functions and correspond to the maximum values of their superposition.
By means of the proposed approach, geological and hydrodynamic models of the unconventional reservoir were successfully created, which made it possible to estimate the distribution of its initial and remaining oil reserves for all reservoir formations. The options for further reservoir development were also considered including the reactivation of non-operating wells, drilling new wells, and initiation of waterflooding. The obtained results confirmed that waterflooding was able to enhance the cumulative oil production of the reservoir compared with the base case without waterflooding, and its role became more significant as the number of operating production wells increased. The calculated results also showed that the proposed approach was quite sensitive to the changes of input parameters, for example, to the number of production and injection wells. The cumulative oil production varied several times depending on the considered option. The calculated results justified the ability of the proposed approach to forecast the development results and to choose the proper strategy for the reservoir reviving. A distinctive feature of the proposed approach was its ability to adapt to any of geological and field conditions, such as the extremely low initial oil saturation that most reservoir simulators do not take into consideration.
Underbalance Coiled Tubing Drilling in Tight Gas Reservoir Study Case Onshore Field, Abu Dhabi
Authors: Ladmia Abdelhak , Culen Martin , Al Katheeri Abdulla Bakheet , Al Hosani Fahad Mustfa Ahmed , Edmonstone Graham F. J. , Mantilla Alfonso , Baslaib Mohamed Ahmed , Nabil Ihab Mohamed , Yousfi Fawad Zain , Al Hosani Mariam Ahmed , Almenhali Salem Saleh , El Shahat Ayman , Abdulsallam Fouad , Al-Khatib Haitham Mohamed , Al Jaberi Fawzi Omar , EL Beshr Huda , Mcneilly Kevin Dean 
Published: November 2020

Abstract
Coiled Tubing Drilling (CTD) has been growing and developed rapidly through the last two decades. There have been numerous highly successful applications of CTD technology in Alaska, Canada, Oman and the United Arab Emirates (Sharjah Sajaa and Dubai Murgham fields), among other places. Currently, Saudi Arabia has undertaken a campaign for the last seven years that has shown successful results in gas reservoirs.
ADNOC initiated a trial Coiled Tubing Underbalanced Drilling (CTUBD) project in the onshore tight gas reservoirs in Abu Dhabi, United Arab Emirates beginning operations 1-December-2019. The initial trial will consist of three (3) wells. The purpose of the trial is to assess the suitability of CTUBD for drilling the reservoir sections of wells in these fields, and further application in others.
The reason for choosing coiled tubing for drilling the reservoir sections is based upon the high H2S content of the reservoir fluids and the premise that HSE can be enhanced by using a closed drilling system rather than an open conventional system.
The three wells will be newly drilled, cased and cemented down to top reservoir by a conventional rig. The rig will run the completion and Christmas tree before moving off and allowing the coiled tubing rig to move onto the well. The coiled tubing BOPs will be rigged up on top of the Christmas tree and a drilling BHA will be deployed through the completion to drill the reservoir lateral.
The wells will be drilled underbalanced to aid reservoir performance and to allow hole cleaning with returns being taken up the coiled tubing / tubing annulus. The returns will be routed to a closed separation system with produced gas and condensate being primarily exported to the field plant via the production line, solids sparge to a closed tank or pit and the drilling fluid re-circulated. The primary drilling fluid will be treated water; however, nitrogen may be required for drilling future wells in the field and will be required regardless for purging gas from the surface equipment during operations. A flare will also be required for emergency use and for start-up of drilling. If the trial proves a success, a continuous drilling plan will be put in place.
A Thermodynamic Robust Model to Assess Hybrid Solvents for CO2 Capture
Authors: Alkhatib Ismail , Al-Hajaj Ahmed , Abu Zahra Mohammad , Vega Lourdes 
Published: November 2020

Abstract
The molecular-based soft-SAFT equation of state has been applied to describe the chemisorption of CO2 in non-aqueous hybrid solvents of mixtures of AMP and glycols. The reactive nature of the CO2 absorption process in non-aqueous amines was implicitly modelled by the formation of CO2-amine physical aggregates bounded by strong and localised intermolecular interactions. This modelling framework only required VLE data on the absorption of CO2 in amine solvents, without the need for additional information such as speciation reactions or equilibrium constants. Subsequently, the developed models were used to examine the CO2 capture performance of these hybrid solvents in terms of absorption cyclic capacity and heat of regeneration as key performance indicators using a simple and short-cut estimation method. Results show that for the same total amine mass concentration, non-aqueous AMP solvents possess a 30-40% decrease in total heat of regeneration compared to their aqueous counterparts at the expense of a 20-50% reduction in cyclic capacity. These results validate the reliability of the molecular modelling approach as an attractive and valuable tool for the screening of chemical solvents and process modelling.
Impact on Corrosion of Different Types of EOR Polyacrylamides in Various Conditions of Salinity and Temperature
Authors: Bonnier Julien , Martin Vincent , Rivas Christophe 
Published: November 2020

Abstract
Fossil fuels currently supply more than 85% of world's energy, and global energy demand and consumption is forecasted to go up rapidly over the next 20 years [Jamaloei et al., 2011]. Such demand can only be satisfied by sustaining the production of energy in existing fields.
Therefore, Enhanced Oil Recovery from existing fields has become increasingly important. Polymer flooding is one of the most efficient EOR technologies that started as early as the late 1950s [Standnes et al., 2014]. Adding polymers increases the viscosity of the injected fluid downhole, which helps to push out viscous crude oil for better oil recovery (up to 10-15% over water flooding) [Standnes et al., 2014] [Taylor et al., 1998]. Among them, Hydrolyzed polyacrylamide (HPAM) is gaining popularity in EOR: inexpensive, it can also withstand high mechanical forces during water flooding [Li et al., 2016] [Wever et al. 2011]. Depending on salinity and temperature, co and ter-polymers of PAM with ATBS may be more relevant to be efficient in highly stressed conditions.
Depending on process conditions, industrial equipments such as water pipelines and flowlines are built in seamless carbon steel (CS), stainless steel (SS) and especially duplex (DSS) or superduplex stainless steel (SDSS), capables of transporting fluids at high temperatures and pressures. Since produced water or seawater used in EOR processes bring species prone to induce corrosion (most notably carbon dioxide, hydrogen sulfide and sulfate, dissolved oxygen), several corrosion modes are possible : uniform corrosion of CS, pitting and crevice corrosion of SS, Microbiologically Influenced Corrosion (MIC). Technologies such as upstream deoxygenation of the fluids, addition of oxygen scavengers and corrosion inhibitors and/or addition of biocide are used [Voordouw, 2011].
The corrosion mechanisms of CS in synthetic and industrial brines in presence of CO2 and H2S are often studied, but the effect of viscosifying polymers on corrosion is not well documented. This study aimed to improve the knowledge on the effect of PAM based viscosifying polymers on corrosion of CS and SDSS.
Enhancement of Sub-Surface Completion Integrity by Mitigation of Complex Layered Scale/Asphaltene Deposition in Gas Wells
Authors: Al Jaberi Fawzi Omar , Albadi Mohamed Mubarak , Al Zaabi Saleem Salman , Ahmad Zeeshan Ahmad , Gadelhak Abdelrahman Mohamed , Cristea Zaharia Cristea , Ansari Saad Wajih 
Published: November 2020

Abstract
This study established the detailed root cause of complex layered scale deposition along the completion jewellery and production tubing, qualitative and quantitative scale composition, special design of the scale treatment and future mitigation plan to handle the scale/asphaltene issues in ADNOC Onshore gas wells. Gas producers are having scale problems due to corrosion products with mixture of organic material deposition which may be from produced gas and condensation of heavier hydrocarbon due to change in pressure temperature profile along the tubing. Gas injectors are having scale/asphaltene deposition indicating the lubricant components thus suggesting an exogenous source of scaling (i.e. external sources such as oilfield tools, seals, valves, upstream equipment).
Two stage chemical scale treatment designed after conducting extensive lab test to reach the 75 – 80 % solubility cost effectively. Mechanical treatment with sterling beads evaluated for hard scale by considering the tubing integrity. Scale treatment operation executed with coil tubing at 3 wells and successfully achieved the desired results.
Identified the root causes of scale build up and chalked out future mitigation plan to maintain the well integrity, flow assurance and cost optimization. In short term, scale issues can be handle by evaluating the suitable chemical with reference to well type, improving chemical injection system to minimize the corrosion products and improving the quality of injected gas for gas injection system. In the long term, scale formation can be avoided by squeeze inhibition treatment (scale/corrosion), mechanical treatment of scale removal for hard scale and improving in downhole completion jewellery maintenance.
First Real-Time Fiber Optic Surveillance and Analysis of a Bullhead Stimulation of an Extended-Reach Horizontal Lateral in a Giant Offshore Carbonate Oil Field
Authors: Seabrook Brian , Kiyoumi Ahmed , Sau Rajes , Othman Alaa , Almarzooqi Laila , Altamimi Ahmed , Wheatley Edward Jason , Correia Gladwin , Lolla Sri , Campbell Bryce , Shuchart Chris , Angeles Renzo 
Published: November 2020

Abstract
A giant carbonate field offshore is being redeveloped using extended-reach horizontal laterals, up to more than 20,000 ft. with open-hole un-cemented liners, drilled from artificial islands. Previously, SPE171800 introduced an innovative Limited-Entry Liner (LEL) design that enables high rate aggressive stimulation of these wells by bullheading. These wells provide significant profitability in unit development cost, though it is critical to effectively stimulate the entirety of the long laterals to maximize reservoir recovery. Recently, Sau et al. 2019 presented our first application of real-time fiber optic surveillance during the successful stimulation of a water injection well with a 12,000 ft LEL lateral section. Fiber optic distributed temperature and distributed acoustic sensing (DTS/DAS) data were collected. Qualitative analysis of the real-time data were compared with a subsequent production logging tool (PLT) to confirm the effectiveness of the LEL completion and also the validity of the real-time fiber optic data.
This current paper describes the detailed analysis of the DTS/DAS dataset collected and the information that can be extracted from it regarding the effectiveness of the well stimulation. Also presented here is how DTS/DAS can be used to monitor the completion performance during injection; quantitative DTS/DAS analysis provides detailed insight into the acid volume injection into each compartment as well as post-stimulation water injection profile over time and at different injection rates. Recommendations are made regarding how to use the data from future DTS/DAS enabled stimulation jobs to extract the most value from real-time measurements and how permanently installed fiber optic DTS/DAS systems can be used to monitor the health and performance of such extended-reach injection wells.