bluuebunny/crossref_metadata_2025_split huggingface dataset:
Real-Time Monitoring and Predictive Failure Identification for Electrical Submersible Pumps
Authors: Bhardwaj Abhijeet Sandeep , Saraf Rahul , Nair Geetha Gopakumar , Vallabhaneni Sridharan 
Published: November 2019

Abstract
The maintenance of electrical submersible pumps (ESPs) is a highly capital-, resource-, and manpower-intensive exercise that is traditionally performed by reactive process monitoring of multivariate sensor data. In the reactive paradigm, it is difficult to proactively distinguish between sensor fluctuations, trip events, and failures in real time. This paper presents a real-time alarming system for predictive ESP failure identification by constructing dynamic operating envelopes on real-time sensor indicators using machine learning (ML). This ML model identifies the complex relationships between pressure head, pump losses, and supplied electrical energy. Operating envelopes are dynamically updated and validated by continuously incoming sensor data to provide indicators of ESP trip events. Recommendations for the amount of data required to provide reliable predictions and an alarming system to classify an ESP trip as a failure are also incorporated in the model. The algorithm can identify longer-term trends and deeper functional relationships from historical data, as compared to the traditional engineering approaches used for ESP diagnoses. The new workflow with the predictive model can provide signals two weeks before the actual failure event, as indicated by the traditional workflow. Issues related to sensor data quality, including missing, misaligned, and erroneous data that may result in false positive notifications can be easily improved by incorporating more domain knowledge by subject matter experts and field engineers. The proactive identification of failure events using this real-time alarming system can improve production efficiencies by avoiding deferment losses. It also contributes indirectly by improving, reducing, and automating the time spent in analyzing failure events, such as dismantle, inspection, and failure analysis (DIFA). The alarming algorithm can be gradually incorporated into traditional systems to provide continuous improvements and to add value without incurring the high costs of initial deployment and change management associated with it. This paper presents predictive ML models deployed to analyze real-time sensor data to proactively predict failures in ESPs results. It also provides recommendations related to the use of these workflows to improve operating practices and production efficiencies and to reduce deferment. Similar approaches can be extended to the monitoring of other equipment in real time.
First Dual-Plug Cementing in a 4.5in Liner in Sub-Saharan Africa
Authors: Elizalde Roberto , Drevillon Pierre-Marie 
Published: November 2019

Abstract
Cementing of a casing string or liner is always considered a crucial phase of the well construction process. The difference with the other phases, is that once cement has been mixed and pumped in the well, there is a limited amount of time for operators to take decisions for troubleshooting or surpassing any obstacles encountered, before cement is no longer pumpable, as at such point, decisions become exponentially costlier, and can even result in the loss of the well, or sidetrack.
Steps to mitigate these risks involve extensive pre-planning to identify all possible risk scenarios, and prepare mitigation, elimination and correction methods. Another step is to count with appropriate equipment, backup equipment, and contingency procedures ready to be implemented if required. Decisions such as how much more volume should be pumped if plug bump is not seen, or if volume count should be reset when dart latch is seen, should be reviewed in advance, as a decision-making process cannot take place when the event is seen, as the timeframe to take these decisions are too narrow.
Cementing a liner in a deepwater scenario increases the risks during the operation. Inaccuracies for volume counting during displacement are increased, and in situations when there is a small liner, and the displacement volume is greatly larger than the slurry volume, increases inaccuracies even further. Free-fall of cement is also increased, as a heavier slurry is being displaced throughout a longer interval, until it U-turns at the shoe and is finally placed on the annular space. This also increases the risk of not seeing the dart latch with the plug, not being able to reset the volume count to a more precise volume.
The cementing phase of the 4.5" liner for the Deepwater Total Moho-Nord Albian Project, presented these risks due to the short 4.5" liner interval. The liner interval can be as short as 450 mts of liner length, equivalent to 10 m3 of cement slurry) in comparison with the TOL depth (average 4,100 m MD, equivalent to over 50 m3 of displacement). The risks were increased as the project relies on plug bump to set a series of annular inflatable packers to help seal the formation from water influxes. This meant that if the theoretical volume was pumped and the plug did not bump at the time, displacement had to stop, and the packers could not be inflated. Rotation, which often helps cement placement, was also not an option in this project, as T&D analysis proved that there was a high risk to exceed the torque limit of the liner connections.
All these risks combined, made the cementing operation of the 4.5" liner of the Albian project, one of the most complex and crucial parts of the well operation.
Condition Monitoring of Critical Systems Using Enhanced Partial Stroke Testing Technology and Smart Solenoid Valves
Authors: Harvey Richard 
Published: November 2019

Abstract
Partial Stroke Testing was developed to assist in the management of the performance of safety critical ON/OFF valves. The original systems were developed over 2 decades ago and initially PST was just used to demonstrate that the valve can move off its seat. This was considered acceptable as a means of demonstrating safety valve performance. Systems used for this purpose were generally mechanical jammers. These jammers would take the form of snail cams attached to the valve stem, end stops on the actuator or other similar methods. These were used as there was concern that the valve may close during testing and therefore the mechanical jammer makes it impossible for the valve to close if used correctly. There was no diagnostic capability beyond the operator watching the valve move.
As instrumentation advanced techniques used for control valves were adapted for PST purposes and valve positioners became a common method for PST. The main advantage of these systems was that certain parameters could be measured to control the PST and gain data relating to performance. However, the drawbacks were that additional equipment was required and pneumatic systems need to be changed to accommodate them. Add to that a now increased risk of spurious trips and the roll out of this technology had limitations.
Now as we move into the era of Industry 4.0, as described by Marr, 2018 and analytics the industry is moving again to see how valve performance can be better quantified and how condition monitoring can be used to aid in the prediction of failures and facilitate predictive maintenance. This has led to the development of PST systems that have analytics based on position type data combined with the reliability and simplicity of mechanical jammers.
Enhanced H2S Workflow to Assist in Managing the Sour Gases & Oil Production – North Jurassic Digital Oil Field, Kuwait.
Authors: Al-Mai Noura , Al-Shuaib Muna , Alvarado Omar , Al-Nesef Mohammad , Al-Saleh Alaa , Al-Qahtani Shaikha , Useche Marcos , Franco Francy , Orjuela Jaime , Wibowo Arif , Prakash Roshan , Gornescu Bogdan 
Published: November 2019

Abstract
An improved workflow for handling an excess of Hydrogen Sulfide (H2S) in treatment facilities is presented. The objective is for the selection of wells to decrease H2S production by reduction of choke sizes with the lowest possible impact on oil production.
During operational restrictions in a gas treatment plant, it is necessary to reduce the H2S quantity received at the facility. To perform this operation, an approach is to limit the production from wells with the biggest rate production of H2S (volume); another solution is to restrict the wells with the highest concentration of H2S (% molar - composition); However, both scenarios have an impact on oil production. KOC - KwIDF Jurassic, has developed a procedure that considers the derivative of the produced H2S curve as a function of produced Oil to find the optimal scenario.
The proposed method was evaluated using the results from a sequence of monthly allocations that include characteristics such as: facility, number of wells, and fluid compositions. The data was analyzed applying three methodologies that have different objective functions, such as H2S volume, H2S concentration, and a new criterion called H2SOR. As a result, there were three different way to rank the wells to reduce H2S production. A monthly plot of Cumulative H2S Production vs Cumulative Oil Production was prepared to calculate the derivative of the curve, finding the optimal solution at different levels of H2S treatment restriction. Finally, the economic analysis for each method was also calculated.
H2SOR methodology guarantees the best alternative to ensure the restriction of sour gas rates with the lowest impact on oil production. It also proves to be the best solution from the economical point of view.
Deep Learning for Sand Production Analysis and Optimum Workflow in the Greater Burgan Field
Authors: Al-Rashidi Hamad , Safar Abdul-Aziz , Al-Shammari Baraa , Rane Nitin , Muhsain Batoul , Al-Mutairi Talal , Al-Mal Bader , Al-Kandari Noor , Mohammad Dalal , Duncan Bruce , Al-Saeed Hanan , Desai Sameer , Kamal Mariam 
Published: November 2019

Abstract
Meeting 2040 KPC Strategic plan objectives and KOC production targets will require adoption of new cost-effective technologies and methods in Kuwait fields, resulting in incremental oil production and extended life of the fields. Long-term oil production through artificial lift application can lead to pressure depletion and water cut incremental in mature fields, which can cause obvious wellbore impairments, particularly in medium to week formations such as Wara and Upper Burgan formations.
One of the critical parameters that will have great influence on maturing this strategy is sand management-field development. Recently some of high producing wells perforated in Wara sandstone Formation in the Greater Burgan field in Kuwait have been plugged due to sand production issues. Understanding the causes of this critical challenge will definitely help KOC in finding the optimum sand management work flow and select the right sand control technologies to maximize the oil production in Wara formation. Several sand characterization tests were conducted on core plugs and produced samples collected downhole, ESP wellbore data was linked with well logs analysis and production data for understanding the sand production phenomena within the intervals and help establish a sand collapse model. Based on the lab work, modeling and ESP real time data, a screening benchmark was developed for sand management and control for Wara formation. The unique customized screening criteria will support South East Kuwait (SEK) field development to identify/avoid the potential sanding intervals and sustain oil production at safe drawdown pressure, which definitely will prevent ESP failures and extend the ESP lifetime. The risk assessment for potential sanding intervals has been established to predict sand production in most new Wara wells. Some Wara wells targeting shallower or weaker sands would normally be sand control candidates, by taking into account the completion design, optimizing surface sand management workflow, managing safe drawdown and BHFP levels, and taking advantage of favorable stress vectors through oriented perforation can encompass the sand free well operating envelopes over life of well production and depletion conditions.
Success Cases for Temperature Survey in Detection Communication between Tubing Annulus and Integrity Check for Through Tubing Bridge Plug also Cross Flow Determination and Evaluation for Continuous Gas Lift System by Simply Way of Temperature & Pressure Gauges in Gulf of Suez Fields - Egypt
Authors: Zakir Eman Ahmed 
Published: November 2019

Abstract
This paper discuss the major applications of temperature survey that it was applied in gulf of Suez wells in Egypt; the first application is the detection of communication points between tubing and annulus in oil producers through keeping high pressure gas in both tubing and annulus then running the temperature gauge in tubing bleeding off annulus pressure while continuous apply high pressure gas on the wellhead which it is cheap and helpful tool to return the wells to production while it was classified as high risk well by fixing communication points then actions took repair the communication points; the second application is integrity check for through tubing bridge plug leaking by real time monitoring for downhole temperature and pressure while the well is under flowing condition achieving differential pressure and saving rig time ; the third application is the determination of fluid movement both inside and behind the production string, hence locating any holes in the casing and any cross flow between intervals in high pressure temperature formation followed by remedial action for production enhancement ; another application in continuous gas lifted wells is the determination of operating valve (injection point) in gas lifted wells with detecting for any leakage valves that it effect on the lifting system efficiency and it needs change to keep the well’s production from dropping .by this tool production increasing was occurred through repairing the wells with more than 4000 BOPD.
so it is very important to share success applications from using temperature survey in oil producers to other companies to benefit from it because it is very cheap and useful in integrity check for completion / casing holes and through tubing bridge plugs leakage also for down hole fluid movement determination in high pressure temperature formation also in the continuous gas lift system evaluation.
Communication points between tubing and annulus in oil producers was determined easily with low cost and Low risk in operation that it was helped in changing the high-risk wells to safe operating wells by repairing the communication it was helped in oil production increasing; the integrity evaluation for through tubing bridge plug saving rig time / cost was determined; the evaluation of continuous gas lift system for determination the point of injection / the leakage valves to enhance lifting system efficiency.
Application of Well Interference Test Using Distributed Pressure Sensors to Optimize Well Spacing in Unconventional Shale Reservoirs
Authors: Uzun Ilkay , Assiri Wisam , Eker Erdinc 
Published: November 2019

Abstract
The optimization of well spacing has become more important in unconventional shale reservoirs to efficiently design infill developments, estimate the Stimulated Reservoir Volume (SRV), and more importantly the estimation of Ultimate Oil Recovery (EUR) from each well. This paper presents a new analytical solution to estimate the start and end of pseudo-transient flow for the data production analysis where boundary-dominated flow exists in the induced fractures hence estimate the SRV for hydraulically fractured horizontal wells for unconventional shale reservoirs.
This paper presents a semi-analytical model to obtain the pressure transient response to characterize the flow and estimate the boundary effect which can be used to analyze the field data in unconventional shale reservoirs. The results from the model are compared and validated against an in-house developed numerical simulation model. The semi-analytical model is based on trilinear model where the SRV is modeled using dual-porosity idealization. The developed model involves the simulation of interference tests for two hydraulically-fractured horizontal well in unconventional shale reservoir using the real-time distributed pressure data. The proposed asymptotic solution evaluates not only the pseudo-transient in induced fractures but also the matrix.
The pressure measurements from real-time distributed pressure sensors and the production measurement using interference test provide a better understanding of the physical phenomena of the interaction between the parent and child wells in shale reservoirs. This paper presents a new model to assess the interference characteristics in horizontal wells to evaluate the optimum well spacing in unconventional shale reservoirs. It is observed that the production from a well is greatly affected by the distance of the wells, the reservoir properties between the wells, and the matrix permeability. It is presented that if the matrix permeability is lower, the start of the pseudo transient flow is sooner; therefore, the drainage volume becomes smaller. This can be observed by comparing the field data from unconventional shale reservoirs in Bakken and Eagle Ford where the matrix permeability in Bakken is higher than that of the Eagle Ford; therefore, the wells observe longer linear flow regime in higher permeability with larger SRV and in-turn larger well-spacing. The proposed asymptotic solution can also be used to analyze the field data in unconventional shale reservoirs to decipher the productivity and economics of horizontal wells.
To effectively produce from unconventional shale reservoirs, an optimum well spacing is required. This paper presents a novel asymptotic solution to characterize the flow regimes and provide a novel formulation in analyzing the pressure and rate variation with time to forecast future performance.
Innovative Digital Well Construction Planning Solution Enhances Coherency and Efficiency of the Drilling Design Process
Authors: Szemat-Vielma Waldemar , Murray Thomas , Kiaie Ali , Bolchover Paul , Yao Jia 
Published: November 2019

Abstract
The oil and gas industry recognizes that there are significant gains to be had by the implementation of new digital technologies. For well construction planning, the goal is to bring together all domains, all data, and all engineering requirements in a seamlessly interconnected solution. As part of this transformation process, an innovative digital solution has been designed and implemented to cover all different aspects of the well planning and engineering workflows, delivering a step change in terms of capabilities and efficiency.
The use of traditional workflows and solutions often requires a lengthy, disconnected, and iterative processes, which can introduce a lack of coherency between the different teams and engineering processes involved, increasing the planning risks. Given the complexity and the number of disciplines involved in the well engineering process, a high-level collaboration is needed in new planning systems. Considering this as the basis for a change, a novel approach to connect all the well planning workflows demonstrates how the process can be optimized by combining automatic engineering and validation, big data analytics, concurrent engineering, and project orchestration.
The main benefit of a native cloud designed and deployed solution is the simplicity for the user because the architecture handles the interconnection of different workflows, data, and people, resulting in a more effective process. In addition, the solution always accounts for the latest data versions and automatically adjusts when any design change is made to the plan. Moreover, the cloud deployment enables complex big data analytics for offset well data analyses, thus increasing the accuracy of the results and democratizing the company knowledge. Automatic engineering validations are immediately confirmed against changes to the wellbore geometries, trajectory design, drilling parameters, bottomhole assemblies, bits, and rig specifications, among others, to deliver a more accurate and coherent result when compared to a disconnected model application workflow. As a result of this innovative solution, a significant reduction of individual software packages required to plan a well can be achieved. The system delivers a step change in in well engineering performance, with case study examples delivering both high quality results and efficiency gains of 50% and more.
This paper presents a full description of a new industry standard digital well construction planning solution that has the potential to transform the well planning process by providing a step change in collaboration, concurrent engineering, automation, and big data analytics. Furthermore, the cloud-deployed solution challenges will be briefly discussed.
Maximising Production Potential by Successful Application of Deep Azimuthal Resistivity and Geo-Steering of an Appraisal Well in an Interbedded Reservoir – A Case Study from UAE
Authors: Mishra Anoop Kr. , Albooshi M.A. A , Al Ali Ahmed Ebrahim , Sinha Rakesh , Al Hashmi Ghassan , Al Blooshi Abdulla , Mills Carey , Mandl Johannes , Fernandes Warren , Potshangbam Sanathoi , Abdoun Safwat , Hassan Syed 
Published: November 2019

Abstract
Accurately placing a horizontal appraisal well within an interbedded reservoir sequence presents a wide range of challenges especially when there is a lack of nearby control wells. These challenges relate to uncertainties in the formation (dip, reservoir continuity & porosity development) and reservoir fluids (contact depth, transition zone height). In order to achieve the appraisal objectives it was critical to successfully intersect certain zones within the reservoir sequence and ascertain their hydrocarbon flow potential along with quantifying key reservoir properties and fluid boundaries. This data was essential for defining and optimizing the subsurface components of field development planning including well count, expected flow rates and in- place / recoverable resource estimations.
In this particular application the target reservoirs are porous gas saturated carbonates developed within an interbedded Jurassic aged limestone. Well placement in the subject well had the primary objective of intersecting five HC bearing zones while maintaining a safe distance from a conductive zone interpreted to be water saturated. As part of the pre-well planning, 3D real-time multiwell reservoir modelling and its updating capabilities with appropriate LWD measurements for Proactive Geosteering and Formation Evaluation was planned. Based on forward response model from offset well data along with drilling engineering and data acquisition requirements, an LWD suite consisting of RSS, Gamma Ray Image, High Resolution Resistivity Image (Fracture and Fault identification), Neutron, Density and 16 sector Density image along with a Deep Azimuthal Resistivity measurement for early detection and avoidance of conductive/water zones was utilized. This tool is capable of early detection of conductive zones that could indicate either transition zone saturations or water saturated porosity beneath a gas-water contact (GWC).
Application of the Azimuthal Resistivity measurements along with the realtime updates of the subsurface model helped place the appraisal well within the hydrocarbon column and also established the top of the low resistivity "Wet Zone". Importantly, these results were later confirmed with production logs acquired as part of well testing operations.