bluuebunny/crossref_metadata_2025_split huggingface dataset:
Innovation of Sand Management and Conformance Control Design in a Steam Flood in the South of the Sultanate of Oman
Authors: Shizawi Wafa , Zadjali Ruqaya , Riyami Mohammed , Bellmann Lars , Yahya'Ei Haitham 
Published: November 2018

Abstract
A thermal steam project has been successfully implemented in a Petroleum Development Oman (PDO) field in the South of Oman. The steam flood developed the crest of the field and incremental oil recovery from formation A has been obtained. Based on this success expansion of the steam flood in the field is planned. The southern extension will encounter the same formation A as developed at the crest. The northern extension, however, will contain two new formations (B and C).
For these two new formations limited field data on sand production is available, and a sand prediction evaluation for both cold & thermal production conditions is required. Additional to that, the field development strategy requires that the oil producers will be re-completed after steam breakthrough and a flexible placement of the pump above/below the perforations at different phases of the steam flood. Successful implementation of conformance control in wells with sand control has a significant impact on the oil recovery and thus economics of the project.
This paper focuses on formation B. The assessment of the likelihood of sand production and the requirement of sand control was based on a combination of a) actual field data such as sand production, well performance & completion data; and b) a sand production model for the different production conditions (hot and cold) utilizing rock-mechanical data. The sand evaluation study demonstrated that there is a risk of catastrophic sand failure under both cold and hot operation conditions and thus a completion with thermally compliant sand control and conformance control is required for this formation.
Core sieve analysis data were used to determine the Particle Size Distribution (PSD), which was used to select the sand control type and screen slot width. A standalone wire wrap screen has been selected for sand control in formation B.
A completion that combines a standalone wire wrap screen, with the provision of conformance control by isolating perforation intervals, with placement of a 4.5" tubing pump below the (isolated) sand screen is challenging to design. Multiple completion types have been evaluated and a new type of technology for PDO of sand control with an isolation sleeve is proposed to meet the requirements of the field development plan. It is expected that this new design with flexible recompletion of the sand control system will have a large impact on the oil recovery.
Rig Time Optimization During Workover by Predefined Well Integrity Criteria Using MAASP Sensitivity Analysis
Authors: Yugay Andrey , Yousfi Fawad Zain , Jaiyeola Abiodun Isiaka 
Published: November 2018

Abstract
During normal rig workover operations, once the old completion is retrieved, corrosion log is being executed to check the condition of the casing and/or liner as one of the means to establish a way forward. Decision can be made easily in case of pipe found completely corroded or absolutely intact. However, such clear scenarios are not always the case and the decision making takes significant time, specially if corrosion log results are received at night time or during the week end. It may become a subject of hot discussion between involved stakeholders, trying to find a right balance between safety and operations. Therefore Gas Development Operations Subsurface Team of ADNOC Onshore requested Technical Center Well Integrity Team to identify clear criteria in advance, to save rig time and improve business performance and decision making process. Based on this request Technical Center developed a strategy of predefined well integrity criteria's that are being successfully used now, saving rig time during workover and avoiding conflicts between teams in questionable situations.
The method is based on several factors: Maximum Allowable Annulus Surface Pressure (MAASP) calculation as per Norsok D10 standard, application of Double Barrier concept for Secondary Well Barrier Envelope, sensitivity analysis based on MAASP degradation and remained wall thickness of casing and/or liner. This method has already been successfully implemented in several wells during workover operations saving time for decision making. It is planned to be included in the next release of corporate procedures.
Method, explained in this paper can be used as a guideline by all petroleum engineers, drilling engineers, well integrity engineers and petrophysicists who are involved in workover operations, helping them to improve decision making process based on the results of the casing corrosion logs. In addition, the subject of well life prediction and well life extension in standard Company well design is covered, with focus on safety during workover operations.
Ice Plug as a Well Barrier: The Story of Success
Authors: Yugay Andrey , Albadi Mohamed Mubarak , Agarwal Anubhav , Nadder Mohsen Ali , Gadelhak Abdelrahman Mohamed , Masoner Mark 
Published: November 2018

Abstract
The actual case described here is about successful implementation of the freezing plug technology utilized as a well mechanical barrier for the first time in the company's history. The use of the ice plug resolved a complicated integrity issue and the high H2S gas producer well was brought back on to production.
Reduced space for the ice plug placement made this case unique. Despite the challenging conditions of limited accessibility, injectivity, and zero asset experience with this application, the job was performed successfully.
One of the challenges was a corroded surface casing, which is a common problem in Gulf onshore fields. The casing was previously repaired by welding a mechanical sleeve around the corroded area, which limited the plug length. Several additional problems occurred inside the Christmas tree. The wireline retrievable Surface Controlled Subsurface Safety Valve (SCSSSV) became dislocated out of the landing nipple profile and hit the Swab Valve. The Swab Valve was damaged and became stuck in the closed position, and was not holding pressure. The SCSSSV became stuck across the Lower Master Valve (LMV) and the Upper Master Valve (UMV), and left the well with no operable barriers. Well killing operations using high viscous pills ended up with lost injectivity. Different scenarios of curing this problem have been analyzed involving multi-disciplinary teams and contractors.
During further well service operations and the ice plug installation more challenges were encountered; however, all challenges were handled safely. The ice plug, once installed and tested, provided a mechanical barrier that allowed the team to perform the required services and to reactivate the well riglessly, and avoid drilling a relief well. The case was presented internally and the process was initiated to improve availability of this technology on a regular basis due to growing demand in the field.
The lessons learned during the execution of this job and the methods used will be interesting for all companies who operate naturally flowing wells, helping in curing well integrity issues in a safe and cost efficient way.
Sulphate Reducing Bacteria SRB Control and Risk Based SRB Severity Ranking
Authors: Emmanuel J. I. , Shaapere T. T. 
Published: November 2018

Abstract
The annual cost of steel corrosion is estimated to be $2,500 billon across the globe (Small).
Sulphate Reducing Bacteria (SRB) is one of the most implicated Bacteria in internal corrosion failures worldwide. Currently the method for controlling Sulphate Reducing Bacteria (SRB) by the International Oil and Gas Companies (IOCs) to mitigate the risk of Microbiological Induced Corrosion (MIC) on their wet treated or untreated crude oil transmission pipelines or tanks is by either batch treatment or slug treatment by injecting biocide between two pigs or direct injection through quill in the absence of online facilities for launching multiple pigs simultaneously.
The international best practise for the control of SRB is to kill the bacteria in-situ and prevent the contamination of downstream equipment and piping. To increase killing effectiveness and prevent resistant strains of SRB from been developed, biocides are alternated based on planned treatment frequency determine by the corrosion engineer or corrosion consultant that developed the programme. Time to kill test is conducted in the field to determine the concentration and time to kill the planktonic bacteria, however, determining the time to kill for sessile SRB is often difficult to achieve except slug between two pigs is utilised to create maximum contact with SRB in-situ.
Other parameters to be considered when developing a biocide treatment program are the historical data of the pipeline, the mixed flow velocity, Gas Oil Ratio (GOR), Water Cut (Base Sediment) and Water (BS&W), Pipeline topography, pipeline significance factor, maximum pitting rate, maximum uniform corrosion rate and historical leak history.
The method of assessing the risk due to SRB for static equipment (tanks or pipelines) varies from company to company and there is no universally acceptable standard on what to consider as bench mark for best and effective treatment. In addition, the kind of SRB (Sessile or Planktonic) to be monitored in-situ has also been debated by industry stake holders and corrosion practitioners. Whilst some operators monitor only planktonic in water phase, others monitor sessile growth via installed bio-probes and planktonic from oil field water sample microbiological analysis.
This paper present current practise, identify the gaps in the practise and propose risk based approach to SRB characterization to enhance biocide treatment effectiveness and monitoring. It is the intention of the authors to spur a debate that will lead to the development of best practise in biocide treatment strategy by the International Oil and Gas Companies (IOCs). The authors are of the opinion that improving treatment strategy with SRB characterization using risk based approach will result in efficiency of treatment in addition to substantial cost optimisation to the tune of 20% OPEX and 25% CAPEX.
Development and Field Trial of the World's 1st Cloud Connected Wireless Intelligent Completion System
Authors: Green Annabel , Lynch Paul , Bugten Bjarne 
Published: November 2018

Abstract
This paper describes the development and field trials of a wireless intelligent completion system that enables long term monitoring and interval control to enhance production management within new or existing wellbores by connecting the user wirelessly from the desktop to the downhole component of the system, inflow control valves (ICVs).
The effectiveness of intelligent completions for production optimisation and improving reservoir management is well established, yet the use of this technology remains limited to high value, single bore wells. The cost and complexity of these solutions coupled with limitations in well types, interval quantity and poor system interfaces are all factors which have prevented broader application.
An intelligent completion that communicates wirelessly within the wellbore provides dual benefits in completion operations and production management. Eliminating the requirement for control lines addresses many of the limitations of traditional systems, and the all-electric technology provides greater scope for digital well management and integration with surface systems.
A slimline inflow control valve (ICV) has been developed which provides infinitely variable choking capability and multiple integrated sensors. Qualification has been completed to Statoil's/Equinor's existing standard for the qualification of interval control valves adapted and augmented to reflect the differences between the wireless solution and conventional technology.
Several field installations have been performed with the system, two of which are detailed within this paper to demonstrate the performance of the technology. In the first, operations were performed with local only access to surface data which demonstrated the ability to communicate effectively but highlighted some mechanical limitations in the tool itself. Following implementation of design improvements, a second installation was performed which also included a surface management system with wireless interpretation software and cloud connectivity.
The system has been proven to provide robust communication using pressure pulses within the flowing well stream to provide operating instructions to the ICV, and for the ICV to operate as instructed and communicate effectively to the wellhead. Data from the system has been digitally managed and remotely accessed demonstrating the ability to change tool settings remotely.
Integrating a semi-duplex pressure pulse system which operates in compressive fluid environments to provide direct communication between a downhole device and wellhead provides a low energy communication method compatible with extended service life completion tools. The system has been demonstrated with ICV technology in both multiphase and gas environments. In field trial this has been integrated with an intelligent system effectively deploying the world's 1st cloud connected wireless intelligent completion.
An Innovative Workflow for the Petrophysical Characterization of Tight Gas Reservoirs in Argentina
Authors: Zambrano Rafael , Parra Daniel , Lamberghini Lucia , Saldungaray Pablo , Mosse Laurent 
Published: November 2018

Abstract
The formation evaluation of low-porosity tight gas reservoirs in Argentina presents several well-known challenges in the estimation of main petrophysical properties as porosity, clay fraction, permeability, and water saturation. The main goal is to accurately quantify these petrophysical properties with a consistent and reliable petrophysical model. The next task is to reveal the key petrophysical responses that represent the link between petrophysics and production.
The present work describes the main petrophysical challenges faced and an innovative workflow used in the Lindero Atravesado field with clear examples to illustrate the effectiveness of this approach. The workflow involves measurements such as advanced elemental gamma ray spectroscopy, multifrequency dielectric dispersion, and nuclear magnetic resonance (NMR). The advanced elemental gamma ray spectroscopy has been key for the creation of a robust mineralogical model, and to derive the matrix properties used to obtain an accurate porosity free of matrix and gas effects with the combination of NMR porosity. The dielectric dispersion provides a direct estimation of water volume, which, in turn, helps to adjust the conventional method of water saturation from resistivity. The good correlation between the petrophysical properties estimated from the proposed workflow and the core analysis, demonstrates the benefits of using the advanced log measurements. The final step of the workflow consists in the definition of poro-fluid facies determined with a new methodology, called NMR factor analysis, that is based on the extraction of multimodal information from the NMR T2 distribution to determine the optimal number of dominant modes (factors) that allow describing the reservoir. Production logging results showed a good relationship between the poro-fluid facies and reservoir productivity.
Influence of EOR Polymers on Fouling in Production Wells and Facilities
Authors: Mittal Saumya , Anand Saurabh , Venkat Panneer Selvam , Mathur Vinay , Zagitov Robert , Subramanian Jaisankar , Patel Nilay , Hammonds Paul 
Published: November 2018

Abstract
Cairn Oil & Gas, Vedanta Limited has implemented full field Polymer Flooding in Mangala Field and is currently injecting nearly 400,000 bpd of polymerized injection water with average polymer concentration of ~2500 ppm. Partially hydrolysed polyacrylamide (HPAM) Polymer is mixed with source water to create a mother solution of 15,000 ppm concentration at Central Polymer Facility (CPF) and is distributed through a pipeline network to 15 well pads where it is diluted to achieve a viscosity of ~30 cP for injection.
Artificial lift in Mangala is either by Jet Pump or Electrical Submersible Pump (ESP). In producers, a wide range of polymer concentrations are observed in the produced brine. Maximum polymer concentration measured is ~972 ppm and average polymer concentration is ~280 ppm.
Recently, during well intervention activities, it is frequently observed that polymer like waxy deposits are obstructing the free movement of wire-line tools. During jet-pump redressing, polymer deposition was observed in the Body X-over (Reservoir liquid path), check valve assembly, throat and spacer nozzle to throat inside jet-pump. In addition, an agglomerated polymer substance was also observed in the slick line tool string. A general observation is that after a jet pump change, production rate increases sharply followed by rapid decline. This requires Jet Pump Change Out (JPCO) job at regular intervals (every 20 days in few wells). Furthermore, semi soft to hard polymer deposits have been observed in surface facilities i.e. injection water booster pumps, injection water filters and heat exchangers.
Laboratory analysis of the samples collected indicated that the deposit consists of Hydrocarbon, Inorganic Scales and polymer agglomeration. Based on further studies it is observed that the degree of hydrolysis of the polymer deposit significantly increases between 50-80% in Jet pump deposits and up to 90% in heat exchanger samples. Increasing degree of hydrolysis reduces the polymer cloud point below reservoir temperature and heat exchange skin temperature.
Solution to the problem can be identified by controlling the degree of hydrolysis in fresh polymer below 25 mol% and cloud point greater than 120°C, addition of scale inhibitor to the system upstream of scale formation, removal of deposit with a combination of oxidizer and chelant; other options continue to be studied.
Machine Learning Provides Higher-Quality Insights into Facies Heterogeneities over Complex Carbonate Reservoirs in a Recently Developed Abu Dhabi Oilfield, Middle East
Authors: de Ribet Bruno , Jun Jaeho , Kim Yulee , Trowbridge Thomas , Shin Kook S. 
Published: November 2018

Abstract

Objectives/Scope
Because of the complexity of properties and heterogeneities, the challenge in a carbonate reservoir is to predict the spatial distribution of the best reservoir facies. Due to the sparse distribution of wells, uncertainties exist, especially where fewer cored wells are available. The aim of this study was to employ machine learning, using the full dimensionality of 3D seismic data and well data, to predict lithofacies heterogeneities distribution in major reservoirs of the Thamama Group, for a recently developed large UAE onshore field.

Methods, Procedures, Process
This technology generates a probabilistic seismic facies model derived from the 3D seismic data. An association of naive neural networks, each with a different learning strategy, is run simultaneously, to avoid biasing any of the neural network architectures. To train the neural networks, seismic data and the lithofacies at the well location extracted along the wellbore are used as labelled data. To avoid overfitting from a limited dataset, we introduce seismic data away from the borehole (soft data) so that the neural networks can "vote" on their integration to improve the final training dataset before reaching the ultimate learning stage.

Results, Observations, Conclusions
The application of this technique on Lower Cretaceous carbonate reservoirs shows promising results. The analysis of the probability distribution gives good insights into reservoir facies distribution uncertainty. Lithofacies are created from electrofacies by subdividing facies based on hydrocarbons. The resultant prediction was validated through comparison with observations from a new drilled well, adding confidence in the decision-making process when selecting future drilling locations. This method uncovers new potential for seismic data reliability when predicting the reservoir lithofacies away from wells, especially when referring to prestack data with any type of seismic attributes. Using this method, the major reservoir lithofacies can be precisely predicted within the field. As the probabilistic facies model is calibrated to wells, this lithofacies data can be used for both geologic modeling and volumetrics analysis.

Novel/Additive Information
Machine learning techniques were successfully applied to generate lithofacies from electrofacies from the 3D seismic data, leading to accelerated interpretation and reservoir characterization processes. In many cases, they provided faster images of the subsurface while still maintaining accuracy, thus helping to improve the decision-making process when determining new drilling locations.
Integrated Drilling Optimization Approach Delivers Excellent Results to Improve Drilling Efficiency in Remote Artificial Island
Authors: Paila Phalgun , Kirby Cliff , Diaz Nerwing , Aboulkheir Adham , Mahmoud Dalia , Al Kindi Rashid , Kasem Youssef , Benygzer Mhammed , Moreira Rodrigo , Cesetti Maurizio , Singh Rudra 
Published: November 2018

Abstract
Drilling & Completing of the wells faster, safer and at lower costs has always been the primary target for the operating companies worldwide. While it has been achieved by several means through Technology, Innovation, Operational Optimization, Cost Reduction Techniques, Application of Best Practices etc; the operating company still has to deal with multiple contractors, vendors, suppliers and service providers, with each of them having different drivers for success that may or may not align with the primary goal. The concept of Integrated Operations / Services brings in this required polarization of drivers for success to deliver the projects under budgeted AFE & planned times.
In one of such Integrated Drilling Operations Campaign, at an Artificial Island located in Offshore United Arab Emirates, with single focal point for various drilling well services, the learning curve of the project has been very steep with numerous optimization measures taken at the early phase of the project under the continuous improvement process to enhance the drilling efficiency in order to speed up the well delivery. The step change achieved in the drilling efficiency for delivering the 16″ section will be detailed in this paper. The same concept has been applied in other sections with similar success.
The drilling optimization has never been so thorough and need of the hour with the current prolonged challenging market conditions. This paper revisits the drilling optimization by integrating all the associated well drilling services to improve and pursue higher drilling efficiencies. It details in steps, starting with identifying the opportunities of improvement, how the traditional methods & practices were challenged and the revised practices were adopted in design & operational execution to better the performance and deliver the section faster consistently with every well.
The drilling performance of this section after integrated drilling optimization currently holds several records (best footage/day, best footage/24 hours, best onbottom ROP, best average ROP including connections, best connection times, days/1000 ft, faster casing running speeds) in the subject field and also stands out when compared to the other nearby offshore fields in the country. These drilling performance records are combined with good hole quality which have contributed to delivering the fastest 16″ section when one includes casing running and other flat time activities.
With the planned changes alongside the detailed engineering planning & constantly monitored execution, the section has been delivered well after well with improved times. Overall, the drilling phase of this section has been delivered 3 days earlier than the offset wells and contributing to potential savings of up to 18 million USD to the project drilling campaign cost.