bluuebunny/crossref_metadata_2025 huggingface dataset:
Asset Reliability Enhancement by Implementing 100% Integrity Assurance Approach for Well HSE Critical Equipment
Authors: Abou Amad Muhammad , Al Daghar Tareq , Kunhi Shaheen , Iqbal Asif , Basit Abdul , Al-Ketbi Abdulla , Al Muhannadi Rashed
Published: November 2020

"X-Mas Trees, Wellhead and Down Hole Safety Valves" are deemed as Well HSE critical Equipment in Abu Dhabi Oil fields (alike in many other countries round the world). Ensuring 100%, integrity of this critical equipment has always been a challenge in the industry due to equipment aging (above 25 years in operation) and lack of comprehensive international standard guidelines on this subject. Hence, a comprehensive methodology named as "100% Integrity Assurance approach" was implemented for this equipment in order to ensure sustainability and to prevent HSE incidents throughout the well lifecycle. This methodology in turn contributed significantly towards Life extension of the aging equipment by reducing its failure rates.

The 100% Integrity Assurance approach for Well HSE Critical equipment is a broad-spectrum continuous process involving collaboration among multiple disciplines of the organization such as "Well Integrity, Field Development, Field Production and Maintenance teams. The methodology consists of:

Introducing a risk based approach to standardize all requirements of Integrity Assurance activities for this equipment (e.g. frequency of activities to be performed, process, responsibilities, Allowable Leak Rates etc.). Establishment of an automated mechanism to track and report each and every pre-defined Integrity Assurance activity, highlighting areas of improvement to meet 100% compliance. A robust road map to overcome all the challenges hindering the 100% compliance target of these activities. This includes introduction of special procedures, right set of equipment and effective tracking system. Introduction of Non-Weather dependent equipment to carry out activities round the year in offshore environment.

Implementing this methodology resulted not only in improving performance visibility of Well HSE Critical Equipment to whole organization but it also observed to be contributing significantly to Life extension of the aging equipment by reducing failure rates. Based on last 6-years comprehensive data upto 60% Reduction was observed in the Failure rates of HSE critical equipment/X-Mas Tree Valves.

This unique approach involving multiple disciplines of the organization is new and quite fruitful to maintain the integrity of aging Well HSE critical equipment. The methodology is systematic and fulfils exiting gap in the Oil Field Industry, which lacks any comprehensive international guidelines to maintain or extend the life of aging X-Tree and DHSV equipment.
Lifecycle Maintenance and Integrity Management Programme Development During EPC Phase
Authors: Matthews Steve , Rajagopalan Sathiyamurthy , Chikhany Mayez
Published: November 2020

As capital projects execution is increasingly transformed through digitalisation, there are further opportunities to optimise the efficiencies and effectiveness of Engineering, Procurement, and Construction (EPC) phase maintenance, and integrity management programme development. This paper presents a model for the development of lifecycle maintenance and integrity management programmes during the EPC phase. The approach comprises a fully integrated solution for all required work scopes. This model is embedded within an asset management build platform and has been designed to encourage collaborative working and maximise efficiencies during execution.

The approach enables the provision of clear information to the EPC project team highlighting the critical path data requirements and schedules. This provides enhanced definition of Computerised Maintenance Management System (CMMS) build processes, smoother project management, improved consistency and accuracy of the asset register, hierarchy build, materials, inventory content and linkages. Requirements for manual data scraping from engineering drawings, datasheets and vendor documentation have been substantially reduced. Instead, the approach maximises opportunities to standardise and digitise much of data handling and capture required for successful programme development.

The model incorporates simple, robust rulesets for lifecycle maintenance and integrity management strategies, which consider aspects such as: class code, equipment sub-categories, materials, and operating context. This has resulted in consistent, standardised programme development and implementation, while accounting for owner/operator specifications and requirements. Furthermore, the data deliverables and outputs can be used as a basis for CMMS management of change during the subsequent operating phase.
Drill Cutting Waste Utilization as Alternative Material for Road Application
Authors: Wattana Piyarat Ann
Published: November 2020

Drill cuttings contaminated with synthetic based mud is considered as a potential environmental risk for onshore drilling operation in Thailand. With the current drilling waste management practice, these drill cuttings are sent for incineration at a cement kiln plant. This study focuses on evaluating potential utilization of drill cuttings, treating drill cuttings as resource instead of waste, in road application.

Potential use of the drill cutting contaminated with synthetic based mud as fine aggregate replacement in hot-mix asphalt concrete was investigated. Physical and chemical analyses were performed on the drill cuttings for grain size distribution and for presence of heavy metal. The drill cuttings were blended with aggregate for hot mixed asphalt at different percentage. The Marshall stability tests were performed using ASTM D6927 to evaluate strength of the hot mix asphalt produced with the drill cuttings incorporated. The evaluated mix properties were stability, flow, bulk specific gravity, air voids, voids in mineral aggregate and voids filled with asphalt.

The Marshall stability test results indicated that hot mix asphalt produced with the drill cutting incorporated can met criteria for hot mix asphalt concrete in according to Thailand's rural road and highway specifications. The optimum percentage of drill cutting is 10% based on the total weight of the aggregate in the hot mix asphalt. Results from chemical analysis indicated that the concentration of heavy metal in the drill cuttings did not exceed the maximum contaminant levels set by Thailand's regulation. Volatile organic compounds may be emitted from stack of asphalt plant during the production of hot mix asphalt concrete. Therefore, monitoring and analysis of air quality should be performed.

Drill cutting contaminated with synthetic based mud can be used in aggregate for hot mix asphalt concrete. This process offers cost effective and environmentally sound recycling method for drill cutting waste management.
Sanding Propensity Prediction Technology and Methodology Comparison
Authors: Subbiah Surej Kumar , Samsuri Ariffin , Mohamad Hussein Assef , Jaafar Mohd Zaidi , Chen Yingru , Kumar Rajeev Ranjan , Paramanathan Rajendra Nath
Published: November 2020

Sand production in oil/gas wells is an important topic wherein a proper engineering planning is required either to avoid, control or manage it. Ignoring this phenomenon may lead to an unfavorable impact on the overall economics of the field development with additional costs incurred to fix the issues at a later stage. Sand production is normally manifested due to sandstone rock failure. The failure sometimes only manifests at later stages of hydrocarbon production associated to depletion (stress evolution). Therefore, finding the root cause of the failure mechanism and routes to avoid it, is essential. In order to achieve this objective, a proper sand production prediction analysis is required using a geomechanical model. Selection of methodology and technology will be key for accuracy of the prediction, analysis and solution. We proposed a few techniques in this article, that can be adopted during the process to design the best engineering solutions to mitigate sand production. Both simple analytical models and advanced FEM numerical models have been discussed in the paper. The selection of methodology should be based on the overall sand production risk level even though FEM techniques is the best for solving the problem.
Effective Approach for Enhancement of Rigless Well Commissioning
Authors: Syafruddin Muhammad , Handak Samir , Badr Ashraf , Mohamed Hammadi Maryam
Published: November 2020

Rigless well commissioning is an important stage of well completion to deliver a new drilled or worked-over wells (oil producer or water/gas injector) ready for production or injection. Rigless well commissioning employs firstly slick wireline intervention for well accessibility verification, down hole safety valve operability, bottom hole pressure and fluid gradient survey that assists to design the flow to clean commissioning program. Secondly, it employs coiled tubing (CT) and flow to clean (FTC) packages to cleanup the well and if necessary to perform matrix acidizing to improve well productivity or injectivity.

This paper highlights operational constraints of well commissioning and its effective approach from job design, execution and evaluation that have been performed over 250 wells in the span of 5 years operations. The commissioned wells are drilled in the carbonate formation with surface clustered operation in Onshore and Offshore Artificial Islands. It also describes HSE challenges that have been faced in safe handling of return fluid, management of volatile recovered crude oil, simultaneous operations (SIMOPS) with Drilling Rig, Project and Construction (P&C) activities and hydrocarbon flaring in the environmentally sensitive area.

The implemented approach and methodology of well commissioning has evolved significantly to address operational challenges and reducing well commissioning cost by 60%. It proves improvement of operating efficiency of CT and FTC packages based on downhole pressure survey, smart well commissioning, eliminating high risk clean-up operation for injector well, cluster based well commissioning, in-situ return fluid management and arrangement of vertical flare stack in the constraint offshore artificial island. The overall outcomes have achieved technical objective with optimized cost and minimum risk, enhancing rigless package utilization and implementing sustainable and effective field rigless commissioning.
Investigating Geomechanical Considerations on Suitable Layer Selection for Hydraulically Fractured Horizontal Wells Placement in Tight Reservoirs
Authors: Al-Ameri Nagham Jasim , Hamd-Allah Sameera Mohammed , Abass Hazim Hussain
Published: November 2020

The instant global trend towards developing tight reservoir is great; however, development can be very challenging due to stress and geomechanical properties effect in horizontal well placement and hydraulic fracturing design. Many parameters are known to be important to determine the suitable layer for locating horizontal well such as petrophysical and geomechanical properties. In the present study, permeability sensitivity to stress is also considered in the best layer selection for well placement. The permeability sensitivity to the stress of the layers was investigated using measurements of 27 core sample at different confining stress values. 1-D mechanical earth model (MEM) was built and converted to a 3-D full-field geomechanical model to reach perfect layer choice. The analysis of results has diagnosed the maximum horizontal stress direction of NE-SW as determined using both Fullbore Formation Micro Imager FMI and sonic scanner anisotropy analysis. The effect of porosity and permeability compaction as a result of stress changes while reservoir depletion is including on the reservoir simulation model. The choice of best layer and optimum design criteria for hydraulic fracturing is done in the current study using a compaction simulation model with the results of available measurements of geomechanical properties. The results of the simulation model show that the formation sensitivity to stress is an important factor for detecting a suitable layer for horizontal wells placement. The results of MEM indicate that horizontal stress difference (Δσ) and unconfined compressive strength (UCS) are the most important factors among geomechanical parameters affected the layer selection. From simulation results, it was found that 225 to 275 m fracture half-length gives a higher increment in oil production. The optimum number of fracture stages is noticed to be 8 to 10 stages after which the increment in production will reduce.
Mud Cooler and Chiller Packages in High-Temperature Deep Horizontal Gas Wells: A Case Study from Saudi Arabia
Authors: Javay Alexandre , Schmidt Anderson , Franco Nata , Aljuzayri Mohammed , Sarbaoui Nabil , Bansal Sarvodaya , Redrup John Philip
Published: November 2020

The temperature gradient in a giant gas field in the Middle East shows wide differences from one location to another. The drilling environment in slim single-lateral wells is challenging due to the substantial temperature anomalies resulting to multiple drilling tool failures where recorded downhole temperature exceeded 320 degF. This paper focuses on the first implementation of mud cooler with chiller packages in a gas drilling project and how it affected downhole temperature and well delivery performance.

The process that led to the successful implementation of the technology can be summarized in four phases: the analysis of business drivers, preliminary temperature simulations and package design, and compatibility analysis, installation and operation. The identified business drivers included prevention of tool failures, optimization of drilling parameters, reduction of additional trips and the removal of the time-consuming staging procedure. To address these business needs importing HT tools did not seem to be the optimal solution as the temperature anomalies are not experienced in every well; the mud cooler and chiller offered the needed flexibility and cost-efficient solution.

The mud cooler and chiller packages were implemented in a series of high-temperature gas wells and proved to be highly effective in rapidly decreasing the temperature of the mud at surface and substantially cooling down the downhole drilling tools. Maintaining a low downhole temperature throughout the section enabled the reservoir laterals to be drilled more efficiently, with less runs, and with no temperature-related tool failure. At surface, the mud temperature was lowered by more than 40 degF. Downhole temperature reduction measured by the drilling and measurement tools was up to 21 degF. Remarkable performance was achieved, such as the drilling of more than 3,000 ft of 5-7/8″ lateral in a single run while keeping the downhole temperature below 280 degF which was decisive in preserving the downhole tools.

This project is a notable illustration of successful collaboration between different business units within the integrated service provider's organization to design and implement a fit-for-purpose solution to enhance tools’ reliability in high-temperature environments. The key elements which made the implementation successful in extending the runs and eliminating non-productive time for improved well delivery performance will be presented and described in length in the paper.

Integration of the different technologies involved proved to be a key driver of innovation in the project and allowed for faster trials and deployment of new technologies and ways of working. Both the operator and the integrated services provider joined their efforts to achieve step changes in performance in high-temperature gas wells which can be successfully implemented elsewhere with all the main IOCs and NOCs.
Advanced Well Planning Using Natural Language Processing NLP and Data Science Models: Maximizing the Value of Data to Mitigate Costs and Risks in New Wells
Authors: Cumming John , Riggins Valentina , Hodson Paul , Walker Barry
Published: November 2020

A new methodology using data science models and natural language processing (NLP) model has been developed, enabling rapid well screening and automated recommendations of key planning parameters. Well Planning and Drilling engineers are empowered by this approach, able to perform quick analysis of all available relevant data, to come up with drilling plans and budgets, and a template for new wells based on the entire field drilling experience.

"Analog" well and "Cluster" were introduced as key concepts in the methodology. Analog wells are wells that have similar characteristics and are completed in the same reservoir as the proposed new well. Clustering techniques used were tested on a publicly available data set, shared by Equinor for the Volve Field.

Within the given data set, 5 clusters were identified by the similarity-based clustering algorithm. For each well cluster, a distance was calculated between wellbores and the averaged features of that cluster. Wellbores in the same cluster were used to anticipate type, duration and impact of NPT events.

The Similarity Index was introduced and a representative well bore for each of the clusters was devised. This representative wellbore was used as a benchmark for recommending casing, ROP, mud density, expected pore pressure, costs, drilling and completion time, expected NPT, among other parameters.

The results suggested that using a similarity index rather than simply using the nearby wells identified stronger similarities between wells than would be found based on proximity. It was determined that in this data set there were a number of wells that were not in the close proximity to the proposed well which were in fact closer analog wells than those which would have been used by taking the nearby wells.

The pre-calculation of clusters and similarity indices made the process of initial estimation for new wells very rapid and bias-free.

For the NLP exercise, the accuracy of classifying NPT achieved was 98% through selecting the optimal technique. The approach also highlighted the need for a dictionary with common abbreviations used in the drilling industry, to standardize and share meanings of terms across companies and even teams.

The proposed method overcomes the major limitations of user-biased process of manually gathering, with a limited data set transformed to an objective process, is inclusive of all wells in the field, and the value of automating results.

The technique is not a substitute for the detailed well engineering design required to develop a well design to AFE approval standard, however, the tool enables a much needed acceleration in well design achieving significant reduction in time, costs and risks.
Research on Radial Drilling Technology of High Efficient Rock Breaking Under High Temperature Deep Well Conditions
Authors: Chen Zhi , Zhu Feng , Hu Qiangfa , Zhang Youjun , Lv Weiping
Published: November 2020

The current radial well operation technology can not adapt to high temperature, and the long tripping period and low drilling efficiency in deep well conditions.According to the characteristics of abrasive jet, a new radial drilling method is proposed in this paper, in which the abrasive jet is conveyed to the underground by CT (coiled tubing), the casing is sidetracked first, and then the formation is drilled.

The working procedure is that using the CT to run the positioning and guiding tool in hole first, and then using the CT to run a steel tube in hole. When the steel tube reaches the deflector, it makes a radial turn, and the ground equipment transfers the abrasive drilling fluid to down hole through the CT. During the operation, the casing sidetracking is completed with drilling fluid with high abrasive concentration, then the abrasive concentration is reduced, and the steel tube enters the formation to complete the radial drilling.

Practice has proved that when the well temperature exceeds 100°C the jet hose is easy to be damaged under high temperature and high pressure environment, resulting in leakage of drilling fluid and unable to complete the operation normally. It is necessary to select a suitable temperature-resistant jet hose. Practice has proved that when the well depth is more than 4000 meters, the pressure loss along the system increases and the jet water power from the nozzle decreases. For hard formation, the water jet is not enough for rock breaking drilling in the formation. The results show that under the same water power condition, abrasive jet has stronger ability to break rock and penetrate hard stratum than water jet because it contains solid particles with higher hardness and density. At the same time, the abrasive water jet with suitable abrasive concentration and water power can be used for casing sidetracking. The casing sidetracking and formation drilling are combined to simplify the process. Experiments show that the types of abrasives, abrasive concentration, drilling fluid composition, drilling fluid water power, injection time affect the casing window opening and formation drilling effect.

The method introduced in this paper solves the technical problem of water jet radial drilling, which is easy to break jet hose at high temperature (180°C) and can not break rocks due to the decrease of water power in deep wells (4500 m), and expands the application scope of radial drilling technology. Secondly, it simplifies the working procedure and opens up a new construction technology.
Exception Based Surveillance on Gas Lift Performance Monitoring: A Novel Gas Lift Diagnostic Workflow in Field B
Authors: Jing Zhi Kueh , Alamsyah Hafidz , Musa Rizwan , Jamaluddin Muhamad Nasri , Abu Bakar Afdzal Hizamal , Mokhlis Mohamad Mustaqim , Hassan Muhammad Firdaus , Fuenmayor Roberto , Hashim Mohd Hafiz , Harith Mikhail , Trivedi Rajesh
Published: November 2020

This paper presents a process flow of an efficient method to diagnose, identify and optimize non-optimum gas lifted wells for a gas-lifted oil field. During normal day-to-day operations, a Petroleum Engineer's deliverables include well lifting performance analysis as well as optimization. Gas lifted wells are deemed optimized when the injection point is at the deepest mandrel possible and no multi-pointing scenario is occurring. However, the real-life well production can be unstable, corroborated by real-time data of flowing tubing-head pressure, casing head pressure and gas lift injection rate. The analysis of these real-time data can infer non-optimized lifting, where one of the symptoms is valve chatter. This in turn translates to well slugging and affects the whole production system. In a field with a large number of gas lifted wells, the diagnosis of these types of cases requires a substantial investment of time each month. By utilizing this workflow, the time spent for lifting diagnostics can be reduced, as well as contributing to time savings for other meaningful tasks, i.e. designing new gas lift system on non-optimized wells.

The Gas Lift Diagnostic workflow, which is developed using pre-defined logic and the existing well model, eliminates the time-consuming manual task that slows down work and streamlines the processes to generate more value for the business and organization.
Innovative Data Processing QA/QC for the World's Largest 3D Seismic Survey
Authors: Al Dhaheri Afra , Cambois Guillaume , Mahgoub Mohamed
Published: November 2020

With close to 90,000 km2 of onshore and offshore seismic data being acquired and processed in less than 5 years, ADNOC has introduced new innovative QCs to ensure the huge amount of data is properly vetted at each step of the processing sequence. The pre-stack time and depth processing flows are very demanding and amplitudes must be preserved throughout. We present four key diagnostics for QA/QC methods at critical steps in the processing sequence. These selected QA/QC are meant to achieve a resilient seismic data processing outcome amenable to all types of seismic interpretation, either conventional seismic interpretation or advanced seismic reservoir characterization or seismic quantitative interpretation.

Seismic bandwidth is the lynchpin of that QA/QC strategy and it will be kept in the spot light to make sure that no processing artifacts erode the acquired seismic bandwidth and that we ultimately preserve the original six octaves of the recorded seismic data. Additionally utilizing the full seismic waveform, either signal or noise, such as surface waves, ground roll, or mudroll, can help compute long wavelength static solutions. The near surface velocity model is a prerequisite for accurate depth imaging not only for the shallow overburden but also at target reservoir levels. We also explore unsupervised machine learning for the automatic detection of amplitude anomalies in ocean bottom nodes (OBN) and to estimate the velocity of the ground roll or mud roll surface wave noise given the huge amount of data we are dealing with.
Development and Subsequent Field Experiences Using Novel Dendrimeric Asphaltene Treatment Chemistries
Authors: McRae James Alexander , Mat Suandi Lizman , Ben Hamza Salah Eddine , Cole Rachael
Published: November 2020

Precipitation and deposition of asphaltenes is becoming a more common issue in the hydrocarbon production process from high pressure reservoirs. Asphaltenes are organic solids commonly considered to be polyaromatic structures with aliphatic chains, sometimes including other heteroatoms. Asphaltene formation in the near-wellbore area and downstream in production facilities can cause numerous flow assurance related issues.

This paper describes work performed in developing a novel class of materials, using dendrimers as a platform to inhibit asphaltene deposition in oilfield applications. Dendrimers, or hyperbranched polymers, are tree-like structures grown from a central core with repeating subunits that provide high molecular weight compounds.

This paper describes the initial development of the dendrimeric chemistries, including initial crude characterisation, laboratory performance evaluation of the products, and two subsequent successful field treatments. The data presented shows effective reduction of precipitation and deposition of asphaltenes both downhole via capillary injection and topsides in production facilities both previously encountering complicated asphaltene issues.
Derivation of Permeability Logs in Carbonate Cores Using X-Ray CT Textural Analysis
Authors: Dernaika Moustafa , Masalmeh Shehadeh , Koronfol Safouh , Gonzalez David , Aljallad Osama , Mahgoub Faris
Published: November 2020

Permeability prediction is an important step in reservoir characterization for effective modeling of water-flood performance and subsequent EOR processes. Permeability should be determined accurately versus depth in all cored and logged wells in a field. This is normally achieved by the use of cross-plots of core permeability versus core porosity from log-derived porosity in un-cored wells. The main aim of this research is to use X-ray CT images of reservoir cores to identify geological textures and predict permeability based on well-established models in carbonates.

Full-diameter reservoir cores were imaged using dual energy X-ray CT. Porosity logs were derived along the entire cores from the dual energy data. Textural variations were identified from the appearance of the CT images. Statistical sample selection was designed to honor the distribution of porosity and CT-textures. Porosity-permeability correlations were established in the texture domain using plug-scale poroperm data and thin-section photomicrograph analysis.

Plug-scale geological analysis confirmed the CT textures in the images, which allowed the derivation of texture logs along the cores. The porosity and permeability data were fitted into unique trends that were derived from the detailed textural analysis. This process provided the link between the poroperm trends and the different textures in the core enabling permeability to be predicted along the entire whole core intervals.

This paper describes a novel approach of combining textures with porosity to model permeability along the reservoir column. A unique dual energy CT technique was used to ensure that all the core property variations were well represented in the plug-scale core analysis measurements. This analysis will open the way for predicting permeability in un-cored wells using texture information from down-hole image logs. In the future, machine-learning algorithms will be employed following the same workflow for effective permeability prediction in the field.
RSS and Motor Directional Analysis Modelling: The Effect of Local Doglegs on RIH of Completions and Casing
Authors: Nobbs Benjamin , Menand Stephane , Dao Ngoc-Ha
Published: November 2020

Rotary steerable systems (RSS) and steerable motors pose their own unique challenges when modelling the bottomhole assembly (BHA) directional behavior. This paper aims to present a methodology that allows the anticipation of problems such as mechanically stuck pipe or lock up situations when running in hole casing or completion strings. The methodology consists of 3 tasks: evaluation of intermediate doglegs and wellbore tortuosity using a unique Rock-Bit-BHA analysis, modelling of the casing deformation including potential centralization and then modelling the run in hole (RIH) of the completion. The directional capabilities of a BHA are affected significantly by the selection of the drilling bit, type of directional drilling driving system and the type of formation. The resulting trajectory can be either very smooth or very tortuous with significant additional local doglegs. The deformation of the casing as well as the completion post buckling analysis is completed using a robust and field validated 3D stiff string Torque & Drag & Buckling model. This methodology can be applied before, during or after the well has been drilling. Used before or during the well construction process, an indication can be given as to whether the casing or completion can reach total depth (TD) using planned or actual data. Used after a lockup or stuck pipe incident, the methodology can give an indication if tortuosity was a contributing factor. Various field cases are presented and clearly show the benefit of the methodology including post-analysis of stuck standalone-screen (SAS) completion string in complex 3D drain and pre-analysis of completion run in hole (RIH) targeting a specific drain. Correctly evaluating the risk of BHA, casing and/or completion strings getting stuck or locked-up when RIH can ultimately provide a template for ultimate reduction of non productive time (NPT). This modeling results has been verified and discussed in the field.
A Novel Investigation of Power Quality Effects on Premature ESP Failures
Authors: Ratanatanyong Suwitcha , Chalermwai Apisit , Kanchanachinto Tanarat , Chantabutr Sirodom , Wasanapradit Tawan , Chigbo Ikenna
Published: November 2020

Electrical Submersible Pumps (ESP) are an essential artificial lift method in oil fields when the reservoir pressure is insufficient to drive the well fluid to the surface naturally. One of Mubadala Petroleum's operated fields in particular experienced several ESP failures from downhole ground faults, which resulted in a run life much shorter than the typical average run life experienced in similar applications. As such, power supply quality is investigated to understand whether it could accelerate ESP system breakdown.

Commonly, a Variable Frequency Drive (VFD) is employed to optimize operations as the reservoir conditions change. However, VFDs tend to generate transient and harmonic distortions as a result of electronic switching. Measurement tools, such as a power quality analyzer and an oscilloscope, are connected to VFD output to measure its power quality. Partial Discharge (PD) is considered to be a possible factor contributing to electrical failures. As such, a PD tool is connected to the medium voltage supplied to ESP to determine if any PD exists.

The investigation of power supply quality focuses on the percentage of Total Harmonic Distortion (%THD) at three different locations in the system; input and output of VFD, and output of the step-up transformer. Since there are no international standards in place to regulate the power quality output from the drive, different VFD models create different levels of output harmonics. Our results show that two different models can give different levels of %THD, both in terms of voltage and current. However, acceptable levels are observed for all of the designs tested, ranging from 2-15%. Power transient and voltage spikes were also measured during well startup and shutdown period, and indicated no significant differences between VFD models, and no issues of concern.

However, significant levels of partial discharge, as measured in nano-coulombs, are observed at the medium voltage measuring point through to the downhole cable connections. It indicated the possibility of electrical anomalies, which can result in cable insulation failure. The level of partial discharge on each specific connector piece can be performed further during the Dismantle, Inspection, and Failure Analysis (DIFA) process after the equipment is pulled out of the well.

The primary impact of high harmonic voltage distortion in ESP power systems is excessive heating, which can accelerate insulation resistance deterioration. Partial discharge can also contribute to insulation failure of downhole connectors and cable splicing points.

This paper provides a systematic approach to investigate the power quality system supplied to downhole ESP equipment, and the application of a partial discharge measurement method, which is new to the ESP industry.
A Novel Approach to Improve Acid Diversion Utilizing In-Situ Foam Generating Fluids
Authors: Al-Nakhli Ayman , Zefzafy Ibrahim , Ahmed Danish , Kharrat Wassim
Published: November 2020

Acidizing is a common stimulation treatment in carbonate reservoirs. Acid distribution over all layers and areas around a treated well is crucial for the matrix stimulation success. Effective acidizing, especially for long horizontal wells, requires acid diverting technique to insure uniform distribution along the wellbore intervals. Mechanical diversion is costly, while chemical diversion using in-situ gelled acid and viscoelastic surfactants have widely been applied during matrix stimulation. These chemical methods showed not only limited efficiency, but can introduce damage to the treated formation. Several chemical additives and complex formulations usually are used to ensure stability and success of diverting fluid application. This exercise greatly increases the treatment cost.

This study introduces a novel solution to improve acid diversion using in-situ foam generation. Thermochemical fluid is used to generate foam in-situ at downhole conditions, which will divert acid stages into not treated sections of the reservoirs. In this paper, two field treatments of two water injector wells, a vertical and a horizontal, were demonstrated using the new system. The in-situ foam generating fluid was used to divert acid in several pumping stages to ensure homogenous treatment. Pumping sequence and treatment mechanisms were described.

The results showed that in-situ foam generation approach has a very effective performance in diverting acid, with superior results compared to conventional diversion using viscoelastic surfactants. As the new system generates foam downhole, it showed very practical operation procedures. No pumping difficulties are experienced, compared with surface pumping to the foam. Having the reaction activated downhole, made the whole treatment safe and friendly to apply. Foam can occupy large areas, so less fluid is required to divert acid stage. Moreover, no complex formulation was required with several additives to ensure fluid activation downhole, which significantly reduced the overall treatment cost.

The novel method will enable effective and homogenous acidizing of carbonate reservoirs and eliminate the need for viscoelastic surfactants, which is expensive with limited effect. This work presents an effective method to place acid uniformly across a treated well using in-situ foam generation.
The Overlooked Condition Monitoring Technique Multiple Case Studies on Critical Rotating Machinery
Authors: Rengasamy Sankar Ganesh , Nicolas Peton Didier , Seshadri Ramanathan
Published: November 2020

Lateral vibration is the most commonly measured type of vibration in machinery. However, lateral motion in the XY plane does not completely describe all the possible directions of motion of machine components. Torsional vibrations do not get the attention that they should. Since torsional vibration is more difficult to measure than lateral vibration, it is often ignored, due to an "out of sight, out of mind" attitude. In fact, torsional vibration can be quite severe and can produce damaging cyclic stresses that can cause a fatigue failure.

Rotating machines are all involved in the delivery or transformation of power, and power delivery requires transmission of torque. The applied torque causes the shaft to twist about its rotational axis. Thus, instead of measuring displacement relative to an equilibrium position, torsion requires measuring the angle of twist of the shaft at different axial positions. All rotating machineries undergo some fraction of degrees of torsional vibration during operations. In many cases, the torsional vibrations are not as easily identified as the translational vibrations, due to lack of simple and direct measurement devices. Typical damages developed under excessive torsional vibrations include shaft cracks, coupling cracks, gear wear, gear tooth failures, key failures, shrink fit slippage, etc.

Today torsional vibration detection and monitoring becomes an important step in rotating machinery condition monitoring [Eshleman 1977, Muszynska, A. G. 1992, Naldi, L. B. (June 9–13, 2008), Naldi, L. G. 2011]. Today the machinery diagnostic services team of Baker Hughes, Bently Nevada uses ADRE raw data along with self-developed Matlab executable [Huageng, L, Howard, B, Menon, A, Péton, N, Roengchai, C. 2013, Luo, H. C. 2013] application for diagnostic purposes based on phase demodulation process to the signals generated by Keyphasor® or zebra tape of tooth wheels. In this article torsional issues will be illustrated with data and pictures using 6 real cases from the industry.
Stratigraphical – Sedimentological Framework for the Thamama Group Development in the Western UAE Based on the Legacy Core Data: How the Key to the Future is Found in the Past
Authors: Ochmanski Tomasz , Wuraola Mopelola , Al Blooshi Abdulla , Al Shehhi Maryam , Swain Ashis Shashanka
Published: November 2020

Our present-day understanding of the Barremian-Aptian depositional systems of the United Arab Emirates (UAE) is predominantly based on the data from the Eastern part of UAE, as well as on the data from the neighboring Oman. With the increasing interest in the development of the petroleum resources in the Western portion of Abu Dhabi, we need to utilize the existing data, which are available. Approximately 1400 feet of the archive core belonging to the Thamama Group and distributed in 5 wells were analyzed sedimentologically and petrologically. The emphasis was put on the comparability with the existing models from the Eastern portion of Abu Dhabi and to the spatial distribution of distinguished lithofacies.

Analyzed sediments are divided into 20 sub-lithofacies, grouped within 8 main lithofacies. Thicknesses, stratigraphical, and spatial distributions of each sub-lithofacies are given. Color and fossil assemblage complement descriptions. Finally, a short commentary with possible interpretations of a depositional environment fulfills each sublithofacies’ characterization.
Innovative Approach Towards Rigless ESP with Dual Completion for Gas Handling
Authors: Saqib Talha , Grifantini Simona , Sabri Abdel Mouez , Keshtta Osama M. , Albadi Bader S. , Beaman Daniel J. , Al-Hassani Sultan D. , Bigno Yann , Draoui Elyes H.
Published: November 2020

Field presented here is located in the southern part of the Arabian Gulf approximately 135 km north-west of Abu Dhabi city. This giant heterogeneous carbonate field consists of multi-stacked reservoirs. The presented reservoir is highly fractured, it measures 9 km by 11.5 km.

The reservoir has an original oil in place estimated at 2,240 MMstb of 35°API oil with saturation gas of 400 SCF/bbl. The reservoir pressure is +/− 2,700 psi and the sealine pressure in the field is +/− 1100 psi. The wells completed in T reservoir are unable to flow naturally against the high sealine pressure. Some wells are producing against by-pass line at 600 psi. Crestal gas injection was introduced to maintain the reservoir pressure.

To produce the reservoir at its potential, it is required to use some artificial lift techniques. ESP was finalized to install for overcoming the high sea line pressure.

As mentioned earlier the T reservoir is naturally fractured and has crestal gas injection, which lead towards 3,500 – 4,000 SCF/bbl and beyond the ESP limit. This requires some solution to handle the gas.

A collaborative team of engineers was assigned to design and meet the challenge of such a premier application. The team conducted a detailed and comprehensive analysis of the T reservoir's fracture and fault characterization: the aim was to deliver an optimal well design meeting the requirement of ESP gas handling with minimum cost.

A unique, fit-for-purpose dual completion (4-1/2" × 2-3/8") was finalized. The rigless ESP will be run through 4-1/2" tubing and 2-3/8" tubing will be utilized for gas handling and re-injecting gas in the sealine at surface. The dual completion will allow to handle high GOR through short string, which will lead towards the long ESP runlife.

Before commencing the full development plan for T reservoir, this will be a pilot for better understanding the reservoir and its behavior.

Rigless ESP was selected due to the advantages compared with conventional ESP: POOH and RIH of retrievable ESP parts through a conventional slickline unitPumps can be replaced during the well life without rig workover.Low OPEX cost.
Advanced Resistivity Modeling to Enhance Vertical and Horizontal Well Formation Evaluation
Authors: Mahiout Said , Liu Chengbing , Polinski Ralf , Kassim Moshood
Published: November 2020

Accurate formation evaluation relies critically, among other inputs, on the correct true formation resistivity (Rt). The common practice in the industry is to use the deep resistivity log as Rt. A single resistivity curve from a deep resistivity measurement often does not represent Rt due to the shoulder bed effect, polarization at boundaries, and many other effects. This is especially true in high angle and horizontal wells. The main objective of the paper is to demonstrate that advanced resistivity modeling workflows for both wireline and logging while drilling (LWD) help in determining Rt by removing or minimizing the impact of all different effects and improving the formation evaluation in vertical and horizontal wells.

Extensive work and computational advances have provided the oil and gas industry with codes to model resistivity tools in a wide variety of formations/conditions. The workflow used is a model-compare-update approach and provides an interface where a layered earth model (layer geometry and property) can be constructed. If available, image logs are used to provide dip information for each layer. After several iterations, and if an agreement between the forward model and measured logs has been achieved (called the "reconstruction check"), this will be a confirmation of the structural model and assigned layer properties. Reconstruction of actual data to modeled data is the confidence indicator. The model changes or iterations can be done manually or automatically. The practical process is usually a combination of both.

As a result, the resistivity logs free of shoulder bed, polarization and other effects are extracted as squared logs for each layer and are used to improve the interpretation methodology and minimize the associated uncertainties to reservoir evaluation. The workflow and benefits of advanced resistivity modeling for improving formation evaluation in vertical and especially high angle and horizontal wells will be discussed. Several field log examples will be used to demonstrate the capabilities of the proposed workflow to enhance formation evaluation in vertical and horizontal wells. Conclusions fromthe work with suggestions/recommendations for the way forward will be presented.

Advanced resistivity modeling when used by the petrophysicists can have many advantages, especially in complex situations. We propose workflows and case studies which demonstrate the value of such advanced modeling in enhancing vertical and horizontal well formation evaluation.
Unique Openhole Metal Expandable Annular Sealing Systems in High Pressure Multistage Fracturing Completion
Authors: Purusharthy Naresh K. , Nugraha Ikhsan , Hassan Zuhair , Wood Kevin
Published: November 2020

This paper describes a game-changing solution regarding the use of metal expandable annular sealing systems in a high pressure multistage frac well. The design and engineering of this technology resulted in the development of fit-for-purpose equipment that overcame challenges often encountered in a high-pressure stimulation environment. The metal expandable annular sealing system was custom designed in order to provide high expansion that can be set in potentially washed out wellbores. The design included a long multi-element sealing system with built-in redundancy to account for fracturing fluid chemical reaction with the rock behind the seals.

The system is just under 4 meters, complemented with multi-elastomer seals, each delivering full Delta P capability within a washed-out hole up to 6.5". The unique design allows full rotational capabilities during deployment, minimizing operational risks.

The system was run in combination with multi open-close fracturing sleeves and a pressure activated toe sub rated to 10,000 psi for acid fracturing in three zones of a vertical carbonate well – the well was known for its heterogeneity and high reservoir pressure contrast. The use of mechanical packers with short sealing elements would have been challenging and increases the risk of unwanted communication between zones. Successful installations, activation of the sleeves and subsequent hydraulic fracturing were achieved, which enabled operational flexibility, reliable isolation and high expansion benefits. Acid fracturing treatment data from each of the stages were analyzed and used to confirm that the zonal isolation integrity.

This paper includes the challenges of providing zonal isolation with conventional packer designs and details the design, testing and qualification of the solution as well as further design modifications for higher fracturing pressure rating.