bluuebunny/crossref_metadata_2025 huggingface dataset:
Autonomous Tracking Performance Analysis of Hierarchical Controller on Various Laying Conditions of Buried Oil and Gas Pipelines
Authors: Sudevan Vidya , Shukla Amit , Sharma Arjun , Bhadran Vishnu , Karki Hamad
Published: November 2019

Middle Eastern countries have the most complex and extensive oil and gas pipeline network in the world and are expected to have a total length of 24066.9km of pipelines by 2022. Routine inspection and active maintenance of these structures thus have high priority in the oil and gas operations. Pigging, the commonly used internal inspection method is expensive and the need for pre-installation procedures for flawless pig operations makes it time-consuming. The external inspection is currently done manually by a group of operators who either drives or walks over the buried pipeline structures. The visual/sensor data collected using various handheld devices are then analyzed manually to identify/locate the possible anomalies. The accuracy of data collected and their analysis highly depends upon the experience of the operators. Also, the extreme environmental conditions like high temperature and uneven terrain make the manual inspection a tedious task. The challenges in the current manual inspection methods can be tackled by using a robotic platform equipped with various sensors that can detect, navigate and tag the buried oil and gas pipelines.

In UAE, the oil and gas pipelines are mostly buried under a berm, a raised trapezoidal structure made up of sand over the buried pipeline structure. The pipelines are buried under the berm either as (i) single pipeline buried in the middle of the berm or as (ii) two pipelines buried on the two edges of the berm. To conduct any external inspection of buried pipelines using a robotic platform, the accurate location of the buried pipeline has to be known beforehand. The proposed Autonomous Robotic Inspection System (ARIS) should have the capability to precisely locate the buried pipeline structure and navigate along with these structures without any fail/skid. A novel hierarchical controller based on a pipe-locator and ultrasonic sensor data is developed for ARIS for detection and navigation over the buried pipeline structures. The hierarchical controller consists of two modules: (i) pipe-locator based tracking controller, that allows the vehicle to autonomously navigate over the buried pipeline and (ii) a sonar-based anti-topple controller which provides an extra layer of protection for vehicle navigation under extreme conditions. An experimental setup, similar to the real buried pipeline condition was built in a lab environment. The autonomous tracking performance of ARIS was tested under various buried pipeline laying conditions. The results obtained show the ability of ARIS to track and navigate along the buried pipeline even in extreme conditions without any fall/skid.
Evolution of Khuff Tight Gas Reservoir Understanding for a Field in Offshore Abu Dhabi
Authors: Menon Pradeep , Anurag Atul , Mills Carey , Basioni Mahmoud , Steiner Stefan , AlBlooshi Mohammed , Dasgupta Suvodip , Guerra Julian , Shasmal Sudipan , Adil Suliman Salim Israa
Published: November 2019

The Khuff Formation is a Permo-Triassic aged carbonate unit which reservoirs a highly economic gas resource in several countries within the Middle East. The appraisal and development of Khuff Formation tight gas resources is the subject of increased focus in the offshore UAE. This case study focuses on the appraisal of a particular field in offshore Abu Dhabi and summarizes how the understanding of this complex reservoir has evolved over time.

The oldest well penetrating the Khuff Formation in this field was drilled almost 3 decades ago. This well tested gas within the Upper Khuff however appraisal of this resource had to wait until 2017-18 when two appraisal wells were drilled on the discovery. These appraisal wells included a complete suite of wireline logs, image log data, formation pressure measurements and well tests to give a clearer picture of the formation and fluid saturations. Subsequent to the drilling of the recent appraisal wells an integrated study was completed integrating all the processed and advanced answer products in order to determine the key elements controlling gas productivity. This knowledge were subsequently applied to optimise a well drilled and production tested in late 2018.

Understanding the production behavior of the Khuff Formation reservoirs intervals has been one of the most critical factors behind the decision to develop this complex reservoir. Certain key answer products are considered critical for identification of completion intervals. These products include; sonic imaging (looking for fractures away from the wellbore), advanced textural analysis from borehole images (porosity classification) and critically stressed fracture analysis from geomechanics. This study led to the conclusion that critically stressed fractures and/or connected pores from images are the best indicators of high gas flow potential, while this flow can become exponentially higher when fractures at the wellbore connect to fractures away from the wellbore. This workflow has now been applied to the most recently drilled well and to other Khuff Formation appraisal projects across the off shore of Abu Dhabi.

This is an illustration of how in-depth analysis of all the acquired data in an integrated manner can help in understanding a complex reservoir and lead to better decision-making for the future wells and offset appraisal projects. Lessons are hidden in both success and failure and as long as these lessons are analyzed properly, they can lead to long-term success.
Practicing Sustainability in Remote Location
Authors: Al Awadhi Ibrahim , Sharma Ashok , Karim Twana
Published: November 2019

Objective/Scope

Effective electrical and instrument control system is required for efficient operation of pipeline network. These equipment are kept in unmanned shelter with necessary cooling, as ambient temperature can go upto 54°C vs designed of 40°C. Pipelines and supply network often run through remote areas where usually no power supply is available. This puts heavy challenges to cooling inside shelters. This paper presents a unique approach adopted to enhance the shelter cooling performance in remote locations.

Methods, Procedures, Process

Conventionally shelter in remote area are Passive cooled shelter (PCS) where water in the exchanger is cooled by using lowest night ambient air. This water is circulated inside the shelter in closed circuit which cools the space by natural convection. High inside temperature (45ºC) was recorded in some existing PCS. To assess reasons for high temperature, performance of PCS and heat dissipations of installed equipment against design values were evaluated. Furthermore, survey was performed for ambient and inside temperature during summer peak time instead of assuming ambient temperature of 54°C. Accordingly, the impact of maximum temperature on instrument was evaluated.

Results, Observations & Conclusions

Study concluded high inside temperature in PCS was due to high heat dissipation and external opening for ventilation in battery room.

Conventionally reduction in maximum temperature inside PCS can be carried out by increasing the capacity of installed external exchangers from existing 300 W/C to 600 W/C. Further benefits can be achieved by installing small fans next to the internal water tank and installing breather diaphragms with filter in external openings to reduce the heat input from outside. However, study concluded that with all this, minimum temperature inside PCS can be reduced to 42ºC vs required 40ºC as all installed equipment are designed to operate at max 40ºC . This is due to high lowest ambient temperature during peak summer (36ºC)

Due to remote location and non-availability of electric power, unique approach of additional cooling using Solar Hybrid A/C system was proposed without battery charger. Study concluded installing Hybrid Solar A/C system without battery charger can be operated during the summer peak time for period of 6 hours per day can bring down the inside temperature below 35°C throughout the year. Proposed solution is now successfully implemented in existing PCS and performance is found satisfactory during peak summer condition.

Novel/Additive Information

There is several PCS with similar issues and this unique approach of installing 24V DC Hybrid Solar A/C system is now being adopted in other PCS shelter which will support ADNOC Way by sustaining safe network operation and 100% HSE. There are large network of pipeline running in remote locations across the world where power availability is a concern and limit were above approach can be followed to realize larger benefits.
Research on Gas Stringer Automatic Deliquification in Sulige Gas Field
Authors: Chen Yong , Gui Jie , Liu Shuangquan , Zhao Zhengyan , Xu Wenlong , Xiao Shuqin
Published: November 2019

Managing numerous gas stringers reasonably and effectively is an arduous work. A system of gas stringer automatic deliquification is presented that uses simulation of opening wells manually and automatic liquid loading identification as its basis for control logic. Technical effects of automatic deliquification in field test are compared to the operations of manual intermittent production and using foam. The new approaches are based on the research on the intermittency of the gas stringer. It considers the factors of tubing pressure, casing pressure, gas production rate, liquid producing, etc. Three algorithms are provided to reach a better effect of deliquification including operation of intermittency, operation of using foam, and operation of combination. Accordingly, reasonable intermittent rules can be set according to the characteristics of pressure and production rate. Simultaneously, fair concentration and amount can be determined as well. Furthermore, the mode of self-diagnosis of upper computer is described. Hardware and software for automatic opening well and automatic injecting foam are development, as well as remote control platform. The effects of using system of gas stringer automatic deliquification are compared to manual intermittent production and manual foam that have been traditionally applied. Four field case studies are presented. Field test in Sulige gas field shows that the average difference between tubing pressure and casing pressure decrease by 0.8MPa and gas production rate increase by 0.2×104m3/d. Meanwhile, the effects of liquid loading are reduced. The most significant effect is that automatic deliquification can make the operations timely and even finely. This is important because in some cases the proper rules are hard to execute for manpower. Besides, costs and labor intensity are reduced. The novelty of system of gas stringer automatic deliquification is in the ability to improve the accuracy and timeliness of operations. Through the research of gas stringer automatic deliquification, fine management of the gas well could be achieved, and the automation level of the gas field could be promoted. It will benefit tens of thousands of gas stringers in the world.
Improved Massive Dolomite Mapping by Integrated Forward Diagenetic and Geological Modeling
Authors: Xu Yin , Lu Peng
Published: November 2019

Stratigraphically discordant massive dolomite bodies of the Upper Jurassic have long been documented because they strongly affect reservoir quality. Dolomitization is affected by varies factors such as original depositional texture, dolomitizing fluid, dolomitization timing and types, and previous diagenetic stages, which can make dolomite bodies either flow conduits or barriers. Therefore, understanding the complex diagenetic system and the distribution of the massive dolomite are extremely important.

In this study, we integrated forward diagenetic and geological modeling following 4-step approach: (1) detailed 3D geologic modeling to delineate the spatial distribution of the massive dolomite; (2) calculation of the effects of dolomitization on reservoir quality; (3) property modeling to predict the spatial distribution of reservoir quality; (4) integrate geological and diagenetic forward modeling to improve the understanding of the dolomitization system and its impact on reservoir quality.

Modeling results indicate that: (1) In general, dolomitization can be divided into two phases, replacement and pore-filling. During the replacement phase, porosity preservation is the dominant process, while during the pore-filling phase porosity decreases sharply with the increase of dolomite volume fraction. Overall, the replacement phase improves reservoir quality, while the pore-filling destroys it; (2) The massive dolomite is heterogeneously distributed with an overall regional trend of decreasing dolomite content southwards; (3) two episodes of dolomitization are likely to occur, supported by multiple types of data, the first is driven by the tectonic compression and developed adjacent to salt basins, whereas the second is related to late hydrothermal dolomitization overprinting the early dolomite.

This integrated forward diagenetic and geological modeling approach helps to better understand the dolomitization mechanisms and regional diagenetic system, by improving the mapping of the massive dolomite and the prediction of reservoir quality.
Automatic Realtime Monitoring of Drilling Using Digital Twin Technologies Enhance Safety and Reduce Costs
Authors: Rommetveit Rolv , Gholami Mayani Maryam , Nabavi Josef , Helgeland Stig , Hammer Raymond , Råen Jostein
Published: November 2019

As part of the digital transformation in oil and gas industry, well construction move toward new efficient methods using digital twins of the wells. This paper will highlight how the drilling operations are monitored, how a digital twin of the well is utilized and how learnings are implemented for future wells.

A Digital Twin is a digital copy of assets, systems and processes. A Digital Twin in drilling is an exact digital replica of the physical well during the whole drilling life cycle. Its functionality is based on advanced hydraulic and dynamic models processing in real time. By utilizing real-time data from the well, it enables automatic analysis of data and monitoring of the drilling operation and offer early diagnostic messages to detect early signs of problems or incidents.

In the current study various actual operational cases will be presented related to different wells. This includes using digital twin during drilling under challenging circumstances such as conditions when using MPD techniques. Also, various diagnostic messages which gave early signs of problems during running in the hole, pulling out of the hole and drilling will be presented. High restrictions were detected using comparisons of real-time values and transient modelling results. These will be discussed.

Different real cases have been studied. Combining digital RT modelled and real-time measured data in combination with predictive diagnostic messages will improve the decision making and result in less non-productive time and more optimal drilling operations.
The Role of Advanced Polymers and Basecoats in High Performance Oil & Gas Coating Systems
Authors: Pernice Guglielmo
Published: November 2019

Over the past forty-five years, thin dry film lubricant (DFL) coatings have continued to evolve to meet continuously changing industry requirements, by introducing novel polymers and coupling them to traditional basecoats. In the case of thin film coatings (~1 mil/25 um) the pairing of these components is especially critical in selecting the proper coating system for the specific application. The objective of this paper is to highlight the proper pairing of these topcoats and basecoats to address material performance expectations and operational requirements.

Historically we have seen the Energy sector use numerous variations of DFL coatings to deliver consistent coefficient of friction (CoF), antigalling and low breakout torque properties. While DFLs have gained wide applicability from bolting to blowout preventers (BOP's) they remain thin films and susceptible to corrosion and mechanical damage unless paired with the proper base coat/primer/pretreatment. An overview of corrosion performance of the coating system via ASTM B-117 will be presented. Furthermore, some of the additional operational requirements which affect topcoats (i.e. abrasion, UV, temperature performance) will be explored based on selected novel binder polymer topcoats.

The results will identify the performance of the coating systems based on singular operational performance requirements, in a variety of environments. These will include corrosion performance expectations with real environment, where possible, with results demonstrating corrosion performance based on the proper pairing of topcoats with Zn Phosphate, Zn Plate, Zn Ni, ceramic metallic and novel Zinc Flake basecoats. Additionally, results will identify the proper topcoat based on UV, abrasion, and thermal operational characteristics using comparative testing standards such as ISO cyclic standard, Taber abrasion and polymer thermal oxidation testing. Tests and results will include and compare PAI, PPS, Polyesters, modified Epoxy systems, as well as novel high temperature Solgel coatings to address the proper positioning of these coating within the proper application performance requirements.

As operating environments and expectations change, coating suppliers will continue to adapt and incorporate new polymer technologies and formulate coating systems, which address the ever-changing industry challenges. Novel coating systems that will be introduced range from the high temperature (800°C) Solgel ceramic like polymer with usage in heat exchangers as antifouling coatings, as well as zinc flake basecoats, which are proven to be effective thin-build high corrosion resistant coatings with conductivity capabilities and lubrication incorporated, meeting API 20E performance requirements.
Innovative Application on Dual Oil Producer Completion: Gas Lift for Lower Zone and Natural Flow for Upper Zone Extends Oil Production in Giant Middle Eastern Oil Field
Authors: Barragan Ernesto , Al Mulla Abdul Naser , Bazuhair Mohamed , Alshalabi Alaa , Cornwall Rachelle
Published: November 2019

A giant oil field consisting of carbonate reservoirs in onshore Abu Dhabi has been provided with long term Field Development Plan, including several Dual Oil Producer (DOP) completions in formations Shuaiba and Kharaib, more specifically in zones A & B to maximize oil recovery. Upper Zone and Lower Zone B have been producing on natural flow using dual completions. This has been possible due to high reservoir pressures available since the beginning of the production.

Conditions have changed, especially for the Lower Zone B, and reservoir pressure has been declining for the past years. As a result, several wells ceased to flow mainly due to lower pressure and/or higher water cut conditions. Therefore, Gas Lift has been selected as the preferred artificial lift method in lower zone B.

The problem has been identified in current dual wells where Upper Zone is still producing but changing dual into Gas Lift single oil producer in lower zone B will translate into halt in oil production in upper zone, therefore reducing the oil recovery for Upper Zone. This is a consequence of the current practice of plugging and abandoning the Upper Zone.

An innovative application for dual oil producer completion with Gas Lift mandrels in long string has been evaluated to keep both zones producing and extend the ultimate oil recovery of the current wells. Candidate selection, including analysis and workflow, will be presented in detail. Moreover, the design process, well modelling and installation will be addressed further in this paper.
Innovative Emulsion-Suspension Systems Based on Nanoparticles for Drilling and Well Workover Operation
Authors: Sergeev Vitaly , Tanimoto Kenji , Abe Masashi
Published: November 2019

A scientific research results represented in this paper show significant improvement of the applied nanotechnologies in the area of oil and gas fields development. Deep experimental research has been done in the period 2017 - 2018 with the goal to create the most environmental and efficient blocking-agent for loss-circulation control and well-killing operation with a minimum negative impact on the natural reservoir system, downhole equipment and surface systems for collecting of oil and gas. The carried out experimental work mainly based on the coreflooding tests which are showed a high-efficiency of the application of nanoparticles with the modified surface for generation of an emulsion-suspension system with incredibly high surface activity and stability properties which can be easily regulated by change the ratio of phases of the emulsion-suspension system [1–7].

The coreflooding tests proved the possibility of the developed emulsion-suspension systems to reach the ultimate blocking effect even in the super-permeable hydraulic fractures with the permeability and conductivity more than 400 Darcy. Four specially developed modifications (samples) of the emulsion-suspension systems with different structure and content of solids have been invented and tested. The results are showed that the blocking effect can be regulated in a wide range of the geological and physical parameters of the petroleum reservoir by change the ratio and type of solids and liquids in the system. The application of the emulsion-suspension systems provides minimal decrease of the hydraulic fracture conductivity - 67 times and the maximum - 7833 times. The synergetic effect of the compositions of solids with different surface charge provides an opportunity to reach reversibility of the blocking effect into the petroleum reservoir system. The reversibility of the blocking effect assures recovery of the rock productivity for hydrocarbon phase. The surface charge of solids makes a positive impact on the wettability of the rock surface. Also, in the paper disclosed laboratory equipment and methodology of the coreflooding tests carried out on the models of hydraulic fractures.
Big Data Insight towards Well planning, A case study
Authors: Akoum Mohamed , Enrique Roswall , Izmeqna Ashraf , Al Nuaimi Seena Mohamed , Waheed Aasim , Kumar Pranav
Published: November 2019

There are various factors that contribute to the Well planning. Be it cost, complexity of the reservoir, safety measures, isolating problem areas, engineering, etc., The whole process of well analysis takes a lot of time and efforts, as the method used is mostly manual. In this abstract, we explain the Big Data approach used to perform Well Planning which significantly reduces the drilling engineer time. Future, possible suggestions to the existing system are also discussed in this paper.

Over the past few years, the concept of Big Data has gradually matured. Drilling Engineers, Data Management and the Solution Development Team have jointly discussed the potential and the functionality if this concept to optimize the Drilling Engineer performance and timeframe for preparing and delivering drilling programs for the new development wells. EDM (Enterprise Drilling Management System), drilling suite of applications, In-House drilling data extraction tool with Web based interface, and many different types of excel sheets, were considered as the input sources. Well planning process was automated for offset and related data acquisition, results and knowledge were captured in a central repository, which will be used in future endaovers.

Fig 1. Shows existing architecture and proposed roadmap to develop a robust system for predicting the new drilling well location. For example, all the data related to NPT records for the wells in the delimited area, their reports, and daily drilling records were brought together. Then, a cutoff value was decided and color coding was used to highlight wells near the offset wells. This layer was overlaid on GIS map to see the exact location and on the In-House web based tool. The criticality was highlighted using the color code. Based on the above, this solution aims to enhance the drilling engineer performance and represents a major contribution towards increasing the efficiency, as wells as the improvement of the drilling operations. In Future, the team plans to add more complex algorithms based on refining the search criteria, extracting data for the offset wells and implementing Artificial Neural Network. The team is also working on connecting corporate datastore for the exploration, production, and development data to EDM. As of now, the EDM is connected to Corportate database through views to access Directional surveys for Wells. Bringing all the data types and sources together has made the analysis of offset wells simpler. The process is more automatic and efficient. It has transformed the process from having local copies of the data, copying data from different sources, and manually applying formulas and generating reports into a centralized repository, in addition to dynamic and automatic reporting. It also, introduces better accessibility from different drilling engineers for enhanced communication, collaboration and knowledge sharing.
Advances in Surface-Wave Analysis Using Single Sensor Seismic Data and Deep Neural Network Algorithm for Near Surface Characterization
Authors: Alyousuf Taqi Yousuf , Colombo Daniele
Published: November 2019

In hydrocarbon exploration, seismic surface waves are used to characterize the near-surface by imaging the subsurface shear wave velocity for geo-hazard investigation and near surface seismic corrections to avoid false structures in the final seismic image. Surface waves, identified in a conventional surface acquisition experiment, can be analyzed in the frequency wavenumber (FK) domain to generate dispersion curves at each shot location. The subsurface shear wave velocity is represented as a 1D profile with lateral variations can be handled using laterally constrained inversion or by applying spatial interpolation of 1D results. We identify two fundamental challenges to perform surface wave analysis. First, inadequate sampling of the surface wave in conventional sensor arrays may create artifacts in the frequency-wavenumber domain, which introduces further distortion in the signal. The use of broadband single-sensor single source land 3D seismic data provides adequate sampling of surface wave energy that is captured with negligible aliasing and high signal power. This makes it possible to record fundamental and higher surface wave modes at large frequencies. Second, it is common in seismic exploration to deal with large amounts of seismic data on several tens of thousands shot gathers of the single sensor survey making manual picking of dispersion curves a tedious and time-consuming job. We developed a deep belief network (DBN) with multiple hidden layers to pick fundamental modes in the phase velocity spectrum. The neural network workflow was trained on 1500 gathers and validated on several 100 gathers. Finally, the automated picking was applied to roughly 50,000 gathers using frequency range (3-30 Hz). The resulting dispersion curves show high spatial correlation and are geologically consistent. The fundamental mode pseudo-section shows smooth changes with significant lateral variations of Rayleigh-wave phase velocities. The second and third mode of dispersion curves are observed in some shots in the F-K spectrum but usually they have weaker energy than fundamental mode. The recent advances in surface wave analysis is presented over a complex structure where the raw data are characterized by strong Rayleigh waves dominated by a fundamental mode. Dispersion curves were inverted using nonlinear conjugate gradients to generate a shear wave velocity model with high vertical resolution for the first 50 m depth. The recent development in seismic data acquisition using single sensor broad band data, and advances in seismic processing using deep neural network lead to a novel technology that enable automatic picking of dispersion curves.
Revised Industry Guidance on Managing Safety Critical Elements
Authors: Scanlon Mark
Published: November 2019

Many organisations operating in the high hazards industrial sectors have process safety management (PSM) systems in place; but what does PSM mean in practice when there are many safety risk reduction measures to manage, and are some more important than others?

The objective was to improve capability of managing safety critical elements (SCEs) by revising the established 2nd edition industry’ technical publication ‘Guidelines for Management of Safety Critical Elements’ (Energy Institute 2007).

Through a cross-company collaborative Energy Institute working group, industry was engaged in a technical development project to capture experience in SCE management since publication of the 2nd edition (Energy Institute 2007). Whilst The term SCE originates in the UK E&P sector legislation, experience is that SCE management concepts in the E&P sector have since been applied internationally across Europe through to Australasia, driven by a European Directive and national requirements, respectively. In addition, industry engagement showed that SCE management concepts also have been applied beyond the E&P sector to petroleum refining and bulk storage, and conventional (thermal) power generation.

The 3rd edition (Energy Institute 2019) has updated the 2nd edition (Energy Institute 2007) so as to: capture industry experience in SCE management; make it applicable to a wider range of facilities, and recognise the range of maturity of international legislation and competent authority requirements for SCE management, which include some that mandate verification through to those with little specific requirement for MAH management. In doing so, the 3rd edition provides: new guidance on SCE development and management in project phases, from initial SCE suitability through to ongoing SCE suitability; new guidance on the role of human and organisational factors in SCE management; new guidance on management of change (MoC), which is a challenge to SCE management; additional guidance on developing performance standards (PSs); additional guidance on assurance aspects of SCE management, to address an imbalance with the amount of guidance on verification; new guidance on implementation of SCE integrity assurance, such as its interface with maintenance management; new guidance on SCE management at system, equipment and component levels; new guidance on determining SCE criticality; new guidance on SCE performance, review and continual improvement, and new guidance on SCE ageing, obsolescence and life extension. In addition, the 3rd edition provides practical examples to support the guidance.

The 3rd edition (Energy Institute 2019) provides a robust and updated ‘industry’ benchmark of good practice in managing SCEs for organisations operating in the high hazards industrial sectors. Adopting its guidance should enable them to ensure initial and ongoing suitability of SCEs, and so contribute to improving their PSM capability.
Pushing the Limits of Depletion Optimization Towards a Hybrid Field Development Plan in a Complex Giant Offshore Carbonatea Reservoir – Comprehensive Scoping of Technical and Economic Viability
Authors: Obeta Chukwudi , Al Dhanhani Helal , Balakrishnan Selvam , Kosik Ivan , Hermann Rolf , Ibrahim Dahir , Nguyen Minh , Shekhar Ravi
Published: November 2019

The subject reservoir is a geologically complex Lower Cretaceous carbonate system, which is on water flood recovery scheme. Due to extreme diagenesis and associated geologic heterogeneity (which include faults, fractures, burrows and algal floatstone), water breakthrough occurred early and oil recovery is low due to water channeling and by-pass of huge volumes of un-swept hydrocarbon. The low recovery performance is compounded by the relative thinness of the reservoir as well as unfavorable mobility characteristics due to disparity in oil and injected water viscosity. The unique interplay of geology and fluid properties confer special displacement characteristics to the reservoir, which despite extensive literature review for similar architectures in a wide range of geologic settings yielded limited results. Despite previous recovery enhancement efforts through workovers, well spacing optimization, and horizontalization, water production has steadily increased. As a key growth contributor in a massive Brownfield re-development project, the reservoir is currently undergoing intensive drill campaign been executed from artificial islands. The strategy underpinning the redevelopment effort involves holistic evaluation, optimization and selective application of innovative well completion technologies, including MRC (Maximum Reservoir Contact), EMRC (Extended Maximum Reservoir Contact), Trilateral, Fishbone, ICV (Inflow Control Valves) and Infill for low-drawdown depletion concept. For Fishbone, the considered design parameters include branch angle, length and numbers. Branch displacement from the mainbore was a key design assessment for Trilateral in view of the potential for injection support buffering by the flank branches. For the Infill, optimizations include spacing and timing. A new ICV logic was implemented on a full field basis to assess incremental opportunity capture through flow restrictions in high water flux intervals. Layer placement sensitivities assessed which zone placement configuration maximizes targeted sweep of bypassed oil. The life cycle production forecast of various completion scenarios per drainage pattern were compared among themselves utilizing technical and economic criteria for identification of the completion that generates maximum value leading to the generation of a hybrid full field, life cycle optimized development plan consisting of MRC/EMRC, Trilaterals, ICVs and infill wells which are currently been executed.
Asset Value Maximization through a Novel Well Completion System for 3d Time Lapse Electromagnetic Tomography Supported by Machine Learning
Authors: Dell'Aversana Paolo , Servodio Raffaele , Bottazzi Franco , Carniani Carlo , Gallino Germana , Molaschi Claudio , Sanasi Carla
Published: November 2019

In this paper, we introduce a new technology permanently installed on the well completion and addressed to a real time reservoir fluid mapping through time-lapse electric/electromagnetic tomography while producing and/or injecting. Our technology consists of electrodes and coils installed on the casing/liner in the borehole/reservoir section of the well. We measure the variations of the electromagnetic fields caused by changes of the fluid distribution in a wide range of distances from the well, from few meters up to hundreds meters. The data acquired by our technology are processed and interpreted through an integrated software platform that combines 3D and 4D geophysical data inversion with a Machine Learning platform equipped with a complete suite of classification/prediction algorithms. Every time new data are acquired, they are fully integrated with the previous database, and used for decreasing the level of uncertainty about the dynamic model of the reservoir. In order to clarify the potential impact of such system on reservoir management, we apply this methodology to a synthetic data set. We discuss a simulation of a scenario where the waterfront approaches the wells during oil production. The goal of our test is to show how to combine our technology with Machine Learning to make robust predictions about the water table variations around the production wells.
Machine Learning Lessons Learnt in Stick-Slip Prediction
Authors: Gupta Soumya , Chatar Crispin , Celaya José R.
Published: November 2019

Downhole vibration remains a major challenge for drillers. Today, there is technology to look at the problem from a unique perspective. A novel look at the problem focuses on evaluation of machine learning algorithms to predict downhole vibrations. Prediction is the first step in a longer road map. The goal would be to find an optimal combination of revolutions per minute (RPM) and weight-on-bit (WOB) to remedy drilling vibration in real-time, hence closing the loop. Drilling mechanics data for thousands of wells, acquired over more than ten years was analyzed. Some preparation of the drilling mechanics data was required. Data cleaning was first performed. This included corrections for time-dependent nature of the data. Data imputing for missing values and handling of outliers and anomalies was also performed in this stage. This was followed by feature engineering which included adding variables based on company-wide drilling domain expertise. Variables to capture data patterns and variables for better capturing the time-series dependencies were also created in this stage.

This paper will discuss methodologies and general rules that were tested for preparing unstructured drilling data. A few of the machine learning algorithms used as building blocks of our full solution are gradient boosting and random forest. Deep learning models were also tested and the value of these are compared. The results were compiled to decide the best algorithm which could further be used to fine-tune optimum performance. The time series aspect of the data is captured in a moving window. As the window increases, the performance of each algorithm also varied. Also, evaluation of the benefits and drawbacks of each algorithm for the drilling predictions is detailed. Ways to improve the accuracy of prediction for downhole vibrations is also suggested with reference to the results showing the logic behind all recommendations. There will be a summary of the details of each finding and a short discussion on the way forward for the industry.
A Novel Thermochemical Fracturing Approach to Reduce Fracturing Pressure of High Strength Rocks
Authors: Al-Nakhli Ayman , Tariq Zeeshan , Mahmoud Mohamed , Abdulraheem Abdulazeez , Al-Shehri Dhafer
Published: November 2019

Current global energy needs require best engineering methods to extract hydrocarbon from unconventional resources. Unconventional resources mostly found in highly stressed and deep formations, where the rock strength and integrity both are very high. The pressure at which rock fractures or simply breakdown pressure is directly correlated with the rock tensile strength and the stresses acting on them from surrounding formation. When fracturing these rocks, the hydraulic fracturing operation becomes much challenging and difficult, and in some scenarios reached to the maximum pumping capacity limits. This reduces the operational gap to create hydraulic fractures.

In the present research, a novel thermochemical fracturing approach is proposed to reduce the breakdown pressure of the high-strength rocks. The new approach not only reduces the breakdown pressure but also reduces the breakdown time and makes it possible to fracture the high strength rocks with more conductive fractures. Thermochemical fluids used can create microfractures, improves permeability, porosity, and reduces the elastic strength of the tight rocks. By creating microfractures and improving the injectivity, the required breakdown pressure can be reduced, and fractures width can be enhanced. The fracturing experiments presented in this study were conducted on different cement specimen with different cement and sand ratio mixes, corresponds to the different minerology of the rock. Similar experiments were also conducted on different rocks such as Scioto sandstone, Eagle Ford shale, and calcareous shale. Moreover, the sensitivity of the bore hole diameter in cement block samples is also presented to see the effect of thermochemical on breakdown pressure reduction.

The experiments showed the presence of micro-fractures originated from the pressure pulses raised in the thermochemical fracturing. The proposed thermochemical fracturing method resulted in the reduction of breakdown pressure to 38.5 % in small hole diameter blocks and 60.5 % in large hole diameter blocks. Other minerology rocks also shown the significant reduction in breakdown pressure due to thermochemical treatments.
Cable Deployed ESP - Solution to Decrease OPEX Reducing Workover Needs and Retrofitting Existing Completion
Authors: Spagnolo Salvatore , Corti Lorenzo , Guglielmo Carmelo , Luppina Salvatore , Maliardi Alberto , Nambiar Vijay , Mollaev Aslanbek
Published: November 2019

The Fully Retrievable ESP System Cable Deployed (CD) is a new technology which permits the rigless deployment of ultra slim OD Electrical Submersible Pump, able to reduce production loss while waiting for work over: these operations should be performed by a proprietary power and load carrying cable, and should be through tubing with the possibility to retrofit an existing completion.

Based on previous Eni Partially Retrievable Experience, a R&D tender was launched among all ESP contractors interested to identify a complete rigless ESP solution. All technologies proposed were evaluated and Novomet was awarded the contract for the trial installation. Eni philosophy was to select the best candidate well which can be representative of the main criticalities of all Eni asset, in order to export the technology in the majority of operated fields. The scouting was performed among all Eni Geographical Business Units (GBU) and finally a well in Italy was selected to be the best candidate. The aim of the test was to install and operate the ESP for a short period of time, in order to validate the technology and diffuse it among the other GBU interested.

It is important to highlight that the well selected is equipped with a Shallow Set Safety Valve, as common practices for ESP installation, so the R&D test will investigate also the functionality of the insert safety valve.

The paper will describe all the steps needed to go further in a Rigless ESP installation project and all the lesson learnt that Eni can draw for the Oil & Gas Industry. The selected solution allows the retrofit option for the current shut-in wells, thus increasing the business opportunity for this type of technology. It is evident that each ESP solution (standard, partially or fully rigless) has pros & cons that will be discussed in the paper to guide the operator in the selection of the best possible option.
Debottlenecking of Oil Processing Train Capacity
Authors: Ray Tapas , Alharam Faisal Ibrahim , Shayea Mohamed Abdulla , Al Hammadi Ali Saleh , AL-Jarwan Abdulla Humaid , Al-Breiki Jumaan Mohamed , Bani Hamoor Mohamed Ali , Rustagi Nagendra
Published: November 2019

There was an urgent requirement for a low-cost fast-track solution to increase the oil processing capacity in one of the ADNOC Offshore facilities in order to facilitate the scheduled maintainence of the Oil Trains as well as to handle additional production before a new train is commissioned. Capacity of each of the four Oil Trains is primarily limited by the vibration problem of the 1st vessel (Inlet Sphere) in the train, due to which field tests could not be performed to establish Oil Train maximum throughput. It was concluded through detailed studies, including Computation Fluid Dynamic Analysis, that there is no techno-economically feasible solution to overcome the vibration problem of the Inlet Spheres. However, the problem could be circumvented if the extra flow is routed to the downstream facilities by bypassing the Inlet Sphere completely. The objective of this in-house study is to find a low-cost solution to overcome the limitation of the Inlet Spheres and other bottlenecks in the trains. Based on the debottlenecking study outcome, it was proposed to use the stand-by Emergency Sphere - while retaining its original design functionality of handling emergency liquid relief - and its associated Crude Transfer Pump to transfer the additional flow (above the Inlet Sphere allowable capacity) directly to the Inlet Sphere downstream system. Similarly, course of actions were also identified for other bottlenecks. Based on the debottlenecking study recommendations, it was agreed to carry out the modification in two of the four Oil Trains considering the Crude Transfer Pump capacity limitation as well as to keep the cost to minimum by maximizing the usage of the existing assets.

Subsequent to the modifications, field tests were conducted and test result showed that the oil-handling capacity of each Oil Train could be increased by 17%. No change in the operating conditions of the existing facilities were required and all the specifications of export crude oil were also met. Based on the test results, other improvements were also suggested. Accordingly, it was concluded to embark on executing the proposed modifications for all the Oil Trains.

The debottlenecking scheme, which is implemented at a cost of ~1 Million USD, is able to generate a revenue of ~2 Million USD per day. Hence, the scheme when extended to the all the four trains would generate a revenue of ~8 Million USD per day. Execution cost for this modification for all the four trains is estimated to be less than 15 Million USD, whereas a new train of similar capacity would cost more than 200 Million USD.

This paper highlights how in-house Technical Support can provide a fit-for-purpose and cost-effective solution to Company’s business needs. The study is a perfect example of "Maximizing Value of Every Barrel Produced".
Unlocking Unconventional Resources in GUPCO: Case Study from Egypt
Authors: Noureldien Darhim M. , Kamal Samy , Hemdan Khaled , Abdallah Hamed , Hassan Alaa
Published: November 2019

The lifecycle of any field consists of three main periods; green, plateau and maturity periods. Currently most of GUPCO fields are brown what made us very concerned to sustain and even increase our production. To achieve that, we have looked at new different options to exploit our resources better. Generally, this can be achieved by whether optimizing current system, applying new technology or evaluating unconventional resources.

One of the high-potential resources that we do have in GUPCO is unconventional resources with many tight carbonate formations. Nevertheless, we did not try to appraise it before since most of our reservoirs are clastics that can be easily characterized and evaluated. On the other hand, tight carbonate formations cannot be characterized or appraised utilizing conventional logging tools or even classical reservoir engineering concepts. It always requires unique techniques relevant to its unique complexity degree especially in presence of micro-porosity and unknown fluid content. This paper sheds light on Appraisal Unconventional Resource Study that resulted in the first successful producer in the company.

GUPCO started to appraise tight carbonate rocks (named Thebes in Lower Eocene) and basaltic intrusion in GoS. This study involved high integration between key disciplines; Petrophysics, Petrology and Reservoir Engineering. To manage uncertainty, we have acquired wide range of data types starting from advanced petrophysical logging tools like Magnetic Resonance, Borehole Imaging and spectroscopy, and full petro-graphic description, reaching to predicting reservoir dynamic performance using measured pressure points (RFT), its analysis and fluid characterization. Ultimately, we have succeeded to completely characterize Thebes formation, and proposing its development plan. The first successful well resulted in 300 BOPD gain as the first successful tight carbonate producer in GUPCO. Development plan is being built to drill new wells targeting unconventional resources including a few possible potential in basalt intrusions, as well.

Dealing with unconventional resources is not an easy task. It requires a lot of work and analysis. Having all of your homework done is not always enough, you have to integrate with interrelated disciplines to link dots and complete the picture. In this paper, we have conceived a new approach in evaluating such formations, and it is a very good example of managing uncertainty by integrating different data to convert hypothesis into reality that can be translated ultimately into oil production and revenues.