bluuebunny/crossref_metadata_2025 huggingface dataset:
Lessons Learned from Trial Testing Wellhead Gas Compressor Technology in a Challenging High Condensate Sandstone Environment
Authors: Al-Rabeh Majed N. , Ruvalcaba Velarde Salvador A.
Published: November 2020

The objective of this paper is to communicate lessons learned, best practices and process enhancement initiatives identified during an actual implementation of Integral Wellhead Gas Compressor technology. The compressor installation was a technology trial test in a challenging high condensate sandstone environment in a conventional gas field. Several technical lessons learned were identified especially in the areas of liquid handling, produced solids management, as well as downhole well intervention requirements.

The methodology was based on collecting and documenting operational challenges and their root causes and corresponding technical solutions as the project progressed. In addition, a benchmarking study was conducted to identify additional areas of improvement to address the root causes of these challenges. Addressing these challenges by implementing the lessons learned highlighted in this paper will ensure expedited project delivery at a reduced cost. Examples of such challenges include unexpected severe liquid slugging, high amounts of solids production, as well as corrosion resistant alloy (CRA) metallurgy requirements.

The benchmarking study resulted in the identification of several areas of potential improvement and multiple engineering process enhancement initiatives were recommended. Examples of such initiatives include the utilization of integrated Liquid Handling System (LHS) to mitigate severe liquid slugging and reduce assembly lead-time. In addition, the utilization of surface cyclonic sand filter systems to mitigate solids production. In addition, conducting downhole tubing drift runs to ensure no restrictions are present that can reduce compressor performance along with several other relevant initiatives.

In summary, the paper provides a deep dive into several technical operational challenges during the actual implementation of wellhead gas compressor technology in a challenging high condensate sandstone environment. Also, several new initiatives are proposed in this paper with the objective of achieving significant cost savings. It is intended for these initiatives to be adopted as best practices not only to yield cost savings but also to supplement the existing best practice literature in the areas of liquid handling, solid management systems, quality control and well intervention.
Innovative Technology Detecting Formation Collapse on Casing- A Case Study
Authors: Ahmad Fajer , Khairallah Eman , Shuber Hussain , Shastri Mukesh , Al-Othman Ahmad , Ramesh Anish , Al Batani Abdulla , Al Foudari Mahmood , Dutta Tapas , Aly Mahmoud , Fituri Mohamed Aiman , Rebaud Paul , Alhamad Nasser
Published: November 2020

Drilling wells in some locations in the Greater Burgan field in Kuwait, can demonstrate significant challenges across the intermediate section. Part of these challenges are combining the carbonate formations with the weak unstable Ahmadi shaley formations at the bottom of the section. This makes it challenging to drilling engineers and difficult to balance between natural mud losses across the carbonate formations and weak shale that requires higher mud weight. Adding to these challenges, the limited surface locations in the field, that forces the well design trajectory to be deviated, which makes the mud window even smaller and shifts it higher. Zonal isolation across this interval adds an additional challenge, as it will prevent gas and liquid to escape from high pressure deeper zones to shallow lower pressure zones and probably to surface, which potentially may cause well integrity issues in the future.

This paper represents a case of formation collapse on a casing prior to cementing operation, how it was detected, how it was handled and how successfully the well was completed.
Safety Recordable Incident Cost Calculator
Authors: Khan Salman , Yaqoob Shamrose
Published: November 2020

This paper describes a project whose objective was to define a costing methodology that showed indicative costs and impacts of safety recordable incidents in an organization. This project's main aim was to raise awareness, through a cost calculator, of occupational health and safety by placing a measurable dollar value to the safety recordable, similar to the nonconformance cost incurred when a quality incident takes place. The novelty of this costing methodology is that it instills a continuous safety culture that is integrated into the employees’ lives, both inside and outside the workplace, making them realize the financial implications of incidents.

Considering current economic crisis and cost pressures mounting on an organization, it is vital to understand the global financial impact of these incidences. In many cases, most organizations have never measured this impact before. This cost calculator will truly be an indicator that demonstrates how effectively an organization is improving its safety performance. Various groups, including safety professionals, project managers, business unit owners, and field service personnel, will be able to see the impact that safety incidences have on the organization as a whole, beyond how it effects their individual rates alone. Organizations can use the output from the cost calculator to not only cut down on the number of incidences they experience, but to decrease their severity as well. In a nutshell, this will provide true transparency and help organizations more completely embody a vision of achieving a zero harm culture.

This paper summarizes the strategic approach used to develop and support the above idea, from inception to final delivery of a costing calculator. The systematic approach used to collect, analyze, and draw conclusions from relevant data is also discussed. The approach described in this manuscript can be adapted to align to complimentary programs and strategic goals and can be scaled in terms of time and resources. It is therefore applicable to any organization.
Utilizing Formation Tester Discrete Mobility and Borehole Images Secondary Porosity for defining Permeability Distribution in Carbonates
Authors: Molua Lyonga Sammy , Maalouf Janine , Shrivastava Chandramani , Ali Humair , Shasmal Sudipan , Khemissa Hocine , Goraya Yassar , Muhammad Ashraf , Al Dhafari Bader Mohamed , Khaled Islam , Alfelasi Ali Saeed
Published: November 2020

Carbonate reservoirs show huge variations in petrophysical properties resulting from leaching/dissolution, fracturation, cementation and or dolotomization. Permeability anisotropy is one property which if understood properly, helps at different stages of reservoir development especially in cases of substantial density difference between fluids; primary production below the bubble point, gas cycling, gas/or water coning etc. Where the anisotropy is severe, it can also influence fluid injection and production rates. For carbonates, microporosity and fractures make it very challenging to relate porosity and lithofacies to permeability. In addition, thin bedded layers that can enhance production maybe unidentifiable because of the coarse nature of conventional logs, at least using Logging While Drilling (LWD) in wells drilled with Oil base muds (OBM) until recently.

The recently introduced LWD dual physics (ultrasonic and resistivity) imaging service with a resolution of 0.2 inch now opens the door to capture heterogeneity using high definition images at very fine scales in OBM that was not possible earlier. High definition borehole images are used to isolate and quantify secondary porosity features like vugs. The density of the vugs per unit length is plotted and correlated to pretest mobility which is a direct indicator to flowrate.

The vug density shows a positive correlation with pretest mobility. The high-resolution images also show intervals where the mobility is enhanced as a result of the influence of thin bed boundaries or where the mobility is lowered because of dense features like stylolytes. The vug density-mobility (vd-m) plot completes a picture of pretest mobility trends limited by the distance between pressure points stations. With the vd-m, more refined facie analyses are possible, together with a better understanding of the permeability distribution across a well.

The effectiveness of a more refined picture of the permeability heterogeneity is seen in the Lower Cretaceous carbonates in an offshore Middle East well. Known porosity variations from core analysis and petrographic images attest to the heterogeneity seen in the vd-m correlation logs. The resolution of vd-m is helpful in understanding the productivity and injection capabilities of such carbonate reservoirs, for example, for optimizing ICD design. Further integration with other data (advanced mud gas analysis) and work processes (geosteering) provide a way of identifying fluid changes in wells, identifying different litho-types and aid in justifying critical geosteering decisions.
Single-Trip Completions Made Simple with a New, Field-Proven Valve Technology
Authors: Dikshit Ashutosh , Woiceshyn Glenn , Kumar Amrendra
Published: November 2020

Interest is high to reliably run single-trip completions without involving complex/expensive technologies. The reward: significantly reduced rig time and completion costs. As described herein, a unique pressure-activated sliding side door (PSSD) valve was developed and field-tested to open without intervention after completion is circulated to TD and liner hanger and open-hole isolation packers are set. A field-proven sliding-sleeve valve that required shifting via a shifting tool run on coil tubing, slickline or wire-line, was upgraded to open automatically after relieving tubing pressure once packers (and/or liner hanger) are set. This PSSD technology, which is integrable to any type of sand control screen, is equipped with back-up contingency should the primary mechanism fail to open. Once opened, the installed PSSDs can be shifted mechanically with unlimited frequency. The two-or three-position valve can be integrated with ICDs (includes AICDs/AICVs) and allows mechanical shifting at any time after installation to close, stimulate or adjust ICD settings.

After a computer-aided design stage to achieve all the operational/mechanical requirements, prototypes were built and tested, followed by several field installations. The design stage provided some challenges even though the pressure-activation feature was being added to a mature/proven SSD technology. Prototype testing in a full-scale vertical test well proved invaluable as it revealed failure mode that could not have appeared in the smaller-scale lab test facilities. Lessons learned from the first field trial helped improve onsite handling procedures. PLT logs run on first installation confirmed the PSSDs with ICDs opened as designed. The second field installation involved a different size and configuration, where PSSDs with ICDs performed as designed. The unique two-or three-position PSSD accommodates any type of sand control or debris screen and any type of ICD for production/injection, which can be easily adjusted at the wellsite. The scope of application is extremely broad. Consequently, more wells that normally could not justify the expense of existing single-trip completion technologies can now benefit from the enormous cost savings of single-trip completions, including ones that require ICD and stimulation options.
Wireline Conveyed Robotic Intervention for Obstruction Cleaning and Sampling in Horizontal Wells Completed with Open Hole – Worldwide First Job Experience
Authors: Yakovlev Timofey , Sagr Hani , Al Harthi Sultan , Aulia Fahmi
Published: November 2020

The objective of this paper is to share the experience of first worldwide job where wireline conveyed robotic cleaning tool was utilized to clean the obstruction in open hole section of oil well while collecting of uncontaminated sample of blockage material.

Wireline conveyed, lightweight, robotic intervention tools were used in one of fields in Saudi Arabia to collect uncontaminated sample of obstructive material for future chemical treatment and to remove the bridge in Open Hole section of oil well, so Workover Rig or Coiled Tubing intervention can be avoided or significantly deferred. Operation was performed without killing the well and with no additional fluids pumped into well, reducing possible intrusion and skin build up. This technology was run first time in world practice to clear an obstruction in Open hole section.

Severe planning was performed prior to technology introduction, including possible solutions comparisons and risk assessment. Robotic intervention was proven not only technically superior, but yielded large economic benefits compared to traditional descaling and sampling methods. It involved less personnel and produced much less CO2 footprint as well.

Sample retrieved during the operation was analysed in laboratory and with high degree of certainty can be attributed as localized formation collapse. Same was confirmed by limited length of blockage that was successfully removed. This represented additional mechanism of wellbore restriction in the field.

The experience from first worldwide operation, the methods and tools descriptions, process, lessons learned, recommendations and way forward will be presented in this work and should be of great interest for wide group of practicing engineers.
Data Driven and AI Methods to Enhance Collaborative Well Planning and Drilling Risk Prediction
Authors: Mohan Richard , Hussein Ahmad , Mawlod Arwa , Al Jaberi Bashaer , Vesselinov Velizar , Salam Fouad Abdul , Al Hadidy Khaled , Pal Anik , Al Yazeedi Haifa , Al Daghar Khadija , Mustapha Hussein , Razouki Ali , Al Hamlawi Imad , El Yossef Bassem
Published: November 2020

ADNOC is continuously enhancing its capabilities to manage its oil and fields efficiently by better planning, execution and operations that drives field development decisions, well performance, and safe operations. In this regard, ADNOC envisages to leverage the evolving Oil and Gas 4.0 technologies to enhance the well planning decisions of the sub-surface and drilling team through data-driven and AI methods.

Effective well planning and operations require collaboration between different subsurface teams and drilling team leveraging multidisciplinary data, historical events and risks and constructing integrated drilling and sub-surface model for collaborative planning and keeping the model live. This requires having a live sub-surface model that is kept close to the field reality while reducing uncertainties. However, extracting key learnings, knowledge and experience from a variety of sources and reports is intense and requires lot of manual processing of data.

An AI-based solution leveraging data analytics, natural language processing and machine learning algorithms is developed to automatically extract knowledge from a variety of data sources and unstructured data in building a live intelligent model that enables effective well planning, predicting operational hazards and plan mitigation. The solution systematically extracts, collects, validates, integrates, and processes a variety of data in different formats such as well trajectory, completion, historical events, risk offset well information, petrophysical data, geo-mechanical data, and technical reports. Newly acquired data comprising drilling events, geological and reservoir properties are integrated continuously to keep the model live and digital representation.
First Successful Fishbone Stimulation Completion in Onshore Oil Field in the United Arab Emirates.
Authors: Quintero Fernando , Talib Noor , Jimenez Alvaro , Chehabi Wissam , Ramarao Subba , Al Nuami Mouza Ali , Al Reyami Mazin , Hapa Cankat , Rodriguez Edward
Published: November 2020

Fishbone Stimulation Technology was developed to increase the well productivity from the tight reservoir for maximum hydrocarbon recovery. Additionally, this technology was implemented in a thin reservoir where conventional stimulation techniques have not been effective and very risky for more aggressive stimulation technique such as hydraulic fracturing.

The application of Fishbone Stimulation Technology was the first time experience representing a massive uncertainity. Thus, a multidisplinary team was estasblished, including members of different departments of the operator and contractors, to design the operational procedures, conduct risk assessment, contingency plans, technical requirements and technical limitations. this first implementation of the fishbone stimulation in ADNOC Onshore served as the benchmark and reference for other fishbone candidate wells in ADNOC Onshore and other ADNOC subsidiaries.

The deployment of the equipment and the production results were a complete success overcoming the risks and previously mentioned uncertainities, closing some gaps from previous partial effective applications in other companies.

The Fishbone stimulation technology will help to increase the well productivity via below mechanism in a well that is too risky to be hydraulically fractured and beyond the coiled tubing reach:

Extension of the needles to connect natural fractures and vertical layers (for reservoir with poor Kv/Kh) Increase reservoir contact Sweep Efficiency of the reservoir
Stress-Dependent Petrophysical Properties of High Heterogeneous Carbonate Tight Oil Reservoirs
Authors: Al-Ameri Nagham Jasim , Hamd-Allah Sameera Mohammed , Abass Hazim Hussain
Published: November 2020

As a reservoir is depleted due to production, pore pressure decreases leading to increased effective stress which causes a reduction in permeability, porosity, and possible pore collapse or compaction. Permeability is a key factor in tight reservoir development; therefore, understanding the loss of permeability in these reservoirs due to depletion is vital for effective reservoir management. The paper presents a case history on a tight carbonate reservoir in Iraq which demonstrates the behavior of rock permeability and porosity as a function of increasing effective stress simulating a depleting mode over given production time.

The experimental results show unique models for the decline of permeability and porosity as function effective stress. This stress sensitivity is even more pronounced in cores with lower initial porosity and permeability. The pores’ size and shape, as well as mineral content provide important reasons for various functions in the stress-dependent behavior of the porous media. Additionally, mercury injection capillary pressure (MICP), thin section (TS) results, scanning electron microscope (SEM) data, and X-Ray diffraction (XRD) are incorporated to relate the microscopic controlling factor to stress sensitivity behavior of this reservoir formation.

The results indicate that permeability is more sensitive to effective stress than the porosity. Different responses to the stress of similar initial permeability are discussed according to their mean hydraulic radius (MHR). Distinguished fabric signatures for the studied reservoir is identified from grouping the MHR-permeability relations, which is significant and can provide insight on the heterogeneity of a given reservoir and how it is related to pore size distribution. This grouping mode provided better data allocation than depending on other parameters such as; conventional samples’ initial petrophysical properties, pore size distribution, MHR values, reservoir stratigraphic units division, and clay content for the samples, which all failed in achieving reasonable data grouping for the tight reservoir under study. A relation of the viscous behavior (ductility/brittleness) of this tight reservoir to permeability and stress is examined.
IT/OT Convergence – Cybersecurity Beyond Technology
Authors: Paredes Ignacio
Published: November 2020

When the first PCs were deployed in industrial automation environments during the 1980s, it was difficult to imagine how the information technology (IT) would influence the day to day operations of industrial organizations. For the last decade or so, the convergence of operational technology (OT) and information technology has been an important topic in organizations whose operations rely on industrial control systems.

The advantages of the IT/OT convergence are obvious – cost reduction, improved capabilities or greater efficiency. However, these advantages come with a cost as they have affected the way that industrial control systems operate and increased the exposure of ICS to cyber risks.

According to one research study, nearly 90% of organizations with connected OT infrastructures have experienced a security breach within their Supervisory Control and Data Acquisition and Industrial Control Systems (SCADA/ICS) architectures, with more than half of those breaches occurring in just the previous 12 months.
Minimizing Erosion of Downhole Proppant Flowback Control Equipment During Fracturing
Authors: Woiceshyn Glenn , Dikshit Ashutosh , Agnihotri Vivek , Chochua Gocha , Noor Mohd Nazri
Published: November 2020

Proppant flowback from hydraulic fracturing is widespread and costly due to erosion and/or blockage of producing hydrocarbons due to proppant accumulation. One remedy is to install sand control equipment integrated into a sliding sleeve device (SSD) as part of the completion string, which raises concern about erosion during fracturing. While some installations have been successful, at least one experienced sand control failure. Computational Fluid Dynamics (CFD) was deployed to evaluate the root cause and identify more robust designs, as presented herein.

Firstly, we identified the most probable causes of sand control failure during multistage fracturing (MSF) in openhole (OH) horizontals. State-of-the-art CFD simulations were then performed on the installed design using actual flow conditions (rates, slurry properties, treatment time) from a failed installation. The static CFD methodology in an initial undeformed geometry proved to be ultra-conservative, so a new quasi dynamic mesh (QDM) methodology was developed, which yielded more realistic (albeit still conservative) erosion-depth predictions. The results revealed areas for improving the design of key components, and CFD was re-run to confirm erosion resistance targets. The modifications were then implemented for a field trial.

Since frack location between two openhole packers is unknown, and the frack port is located between multiple screen/SSD assemblies, one must consider annular flow across the assembly in both directions. Accurate CFD predictions of erosion of completion components versus time during MSF in OH proved challenging. The quicker static methods were useful in ruling out some components as problem areas, such as the sand control media, but proved overly conservative on other key components. The QDM methodology gave more realistic results and indicated that erosion depths in specific locations could be deep enough to possibly cause sand control failure. To reduce the erosion risk, such components were modified, and the result was a reduction in predicted erosion depths to acceptable levels. A safety factor was already built into the predictions because of two key conservative assumptions: ignored initially were 1) particle-particle interaction and 2) erosion of the reservoir wall. The former was further investigated.

While waiting for the field trial results, the main conclusion thus far is that CFD is a valuable tool for diagnosing erosion failures and improving equipment design. However, it’s essential to use a methodology that realistically captures downhole conditions. Presented herein is a more robust design of a screen/SSD assembly for proppant flowback control, as well as an improved CFD methodology for diagnosing sand control failures during MSF and for identifying design improvements of completion equipment. Furthermore, the inherent challenges of controlling proppant flowback without causing erosion or flow blockage of hydrocarbons are discussed.
First Co-Implementation of Inflow and Inter-Well Tracers in Offshore Abu Dhabi: Towards Cost Efficient Reservoir Monitoring and Management
Authors: Lotfy Mohamed , Loobari Sultan , Samantray Ajay , Al Shekaili Fatema , Al Menhali Helal , ELTahir Bashar , Leung Ed , Huseby Olaf
Published: November 2020

This paper presents the integration of two surveillance technologies, inflow & inter-well tracers in an Abu Dhabi Offshore field, for the first time to monitor a complex multi-layered reservoir with early stage water injection. Inflow tracers are chemicals with unique identities, installed into the lower completions that penetrate different layers in the reservoir. Inter-well tracers are also unique chemicals injected into injection wells. Tracer technologies allow non-electric wireless monitoring of the reservoir for many years while reducing cost and operational efficiency. In both technologies, data capture requires to fluid samples to be collected and analysed to detect the unique tracers in the production wells. Inflow tracers provides both qualitative and quantitative estimates of zonal flow as well identifying the source of water breakthrough. Inter-well tracers introduced in the injection wells can identify the primary flow paths and rate of movement of injected fluid in the reservoir. This information can be used to evaluate water channelling and improve water flood conformance plans to maximize sweep efficiency.

The planning and design stage included a selection of pumpable inter-well tracers, volume calculation and breakthrough time simulations to determine the tracer mass required to meet the monitoring objectives. On the other hand, inflow tracers were designed to account for high temperature and highly acidic stimulation fluids and placed along the producing intervals in the lower completion. Quantification models will be utilized to quantify the zonal influx while accounting for expected cross flow. The execution plan is defined by the optimum production and injection rates, equipment and lab test requirements, and optimized field sampling schedule for transient and steady state flow campaigns.

The co-implementation of both tracer technologies in the early stage of waterflood development offers unique ability to monitor the reservoir, eliminating the need for expensive, complicated offshore logistical arrangements for time-consuming wireline interventions to manage the reservoir more efficiently and maximize recovery.
Smart Digital Asset: Single Source of Truth
Authors: Jadhav Satyaprasad , Qrain Afra Al
Published: November 2020

This presentation describes the efforts undertaken by ADNOC Gas Processing's in standards, procedures and process followed for implementing Smart Digital Asset to optimize the time, efforts and resources required Asset Information Management during Engineering, operation, maintenance, and HSE including following, –Present an information on the concept, features, components, software and applications utilised for Smart Digital Asset.–Outline the scope, methodology, limitations, and results of executing Smart Digital Asset for projects.–Describe the value proposition for enhancing and extending the value chain of company's Smart Digital Asset.

Smart Digital Asset is an innovative web-based zero foot print information search engine that provides a single point access to information anytime, anywhere, and on any device. Its focus on the end users sets it apart from other solutions: "Start with what you know such as tag no's, discipline etc." By having all sources of information in Smart Digital Asset solution in one place ADNOC gas Processing noted following benefits, Improve safety & Asset Integrity.Reduce design cycle time for CAPEX\OPEX Projects by knowing impact of changes to other disciplines, compare data stored in different systems for consistency.Cut down on errors resulting from choosing the wrong set of information. Take information into the field on a tablet.Shorten the repair cycleMinimize facility turnaround and outage time.
Did You Know That Collaborative Thinking Can Lift Your Profits?
Authors: Mukherjee Rahul , Al-Suwaidi Eman , Jabbar Shafiulla , Khoori Ziad
Published: November 2020

Objective / Scope

BOROUGE receives its ethane feedstock (De-Ethaniser Overhead DEO) from ADNOC Gas Processing to produce higher value polymer products. As polymer prices continue to rise, capacity utilization of the crackers is the prime concern for BOROUGE during low feedstock availability from ADNOC Gas Processing.

To maximise profit, propane is slipped along with DEO from ADNOC Gas Processing to BOROUGE and co-cracked to produce higher market value polymer products.

Methods / Procedures

The following activities were carried out to evaluate the feasibility of slipping propane along with DEO.

Results, Observations and Conclusions

During the test run, ADNOC Gas Processing’s Train 4 De-Ethaniser column top temperature was increased from minus -3.5°C to +19.5°C and Propane in Ethane product increased from 0mole % to 6 mole %.

Since fractionation column is a multivariable system, disturbance in any process parameter can affect the overall performance and lead to production loss. Hence, the column temperature profile was increased gradually in multiple steps and sufficient time was given between each step change for system stabilization.

When propane from De-Ethaniser column is slipped, Carbonyl Sulphide (COS) also gets slipped with the DEO stream. Higher level of COS in feedstock to BOROUGE may impact their polypropylene product specification. Hence, frequent lab sampling analysis were carried out by ADNOC Gas Processing as well as BOGOURE to make sure the product quality is not impacted.

The test run was successfully carried out for a duration of more than 80 hours. From the test runs results it was concluded that 15 Tons/hr of propane can be slipped with DEO from ADNOC Gas Processing NGL Fractanation Train 4 to BOROUGE which can be converted to value added polymer products.
Cyber Security Incident Response in the Utility Sector
Authors: Simonovich Leo
Published: November 2020

Executive Summary

Protecting endpoint operating technologies (OT) is an increasingly important challenge for the energy sector. As energy companies continue to digitize existing assets and build new assets with intrinsic network connectivity, they present an ever-expanding attack surface to escalating attacks. Trends show that cyberattacks on OT targets have increased in frequency and sophistication. Meanwhile, structural mismatches in the life cycles and maintenance cycles present a challenging business case for companies seeking to defend assets, rendering current cybersecurity best practices both technically difficult and potentially unaffordable to sustain.

Overall, the energy industry has made tremendous progress in maturing cybersecurity capabilities. Yet current practices leave significant gaps due to lag between updates. Put simply, systems patched on Monday are powerless on Friday to stop attacks methods developed on Tuesday, Wednesday or Thursday.

To meet this challenge and answer both the technical and the business case, future cybersecurity solutions need to meet clear requirements: They must function while isolated, remain potent between updates, provide flexibility for deployment in unique, widely varied OT configurations, and must meet or exceed the cost-benefit ratio of current practices. We believe that artificial intelligence (AI) and machine learning (ML) solutions offer these characteristics, as well as ancillary benefits. This paper will describe in detail the current challenges faced by energy companies, the implications of observable industry trends, the characteristics that potential cybersecurity solutions must meet, and why we believe AI and ML technologies can meet these requirements now and in the future.
Offshore Brownfield Slipover Platforms Installation Studies
Authors: Selvaraj Ramesh , Vergil Contraes Geovanni , Karuppusamy Kandasamy K. , Kamal Faris Ragheb , Takieddine Ousama Halim
Published: November 2020

Oil and GAS operators planned to upgrade several existing oil production facilities. The existing jackets are demolished and removed from the seabed with only the conductor wells being retained from the facility. The existing offshore oil and gas platforms could be enhanced to operate for some more years.

The jacket piles from 1.5m below seabed will be cut and together with the jacket demolished. The remainder of the piles below seabed will be left in situ. A new 4-leg standard jacket will be slipped over the existing wells. New conductor wells are to be added to the new jackets. The new jacket will be piled to the seabed with new piles. During design it will be ensured that the new piles do not clash with the exiting piles below seabed. The new jackets the geometric Centre coordinates will be dependent on the existing well layout and the location of additional wells. The jacket locations will be checked for clashes with the existing abandoned piles and feasibility of installing new wells.

The focus of this paper is on the strategies applied in executing Brownfield works for many offshore platforms in Arabian Gulf by National Petroleum Construction Company (NPCC). The case study demonstrates the installation of new four legged Simplified, Standardized and SIMOPS jacket structures onto existing wells using a simplified design approach, standardized seafastening arrangements that requires less offshore work, minimal interface and operations shutdown of live equipment.

To ensure the safe and minimized risk installation operation of Slip over jackets at the existing offshore filed, the cost effective installation methods were devised and implemented to have the successful installation of slip over jackets. These installation strategies help EPC contractor achieve the early completion of the jacket installation in a cost effective way. This strategy places the companies in a better shape such that after the price fluctuation periods, they will be more prepared to face new challenges in developing new fields that will improve their bottom lines and be leaner in their operations. Hence, Operators and EPC Contractors tend to focus on cost efficient and sustainable approaches that will maintain the profit margin and gain competitive advantage.
Digitalization and Remote Monitoring for CP and Chemical Injection in Gas Asset to Enhance Facilities Integrity
Authors: Al-Ghaferi Mohamed Mubarak , Al Janahi Mohammed Ibrahim , Al Jaberi Fawzi Omar , Albadi Mohamed Mubarak , Al Ameri Mohamed Saeed , Al Hosani Ayesha Ibrahim , Shivade Vijay , Zaidan Hassan Khamis , Abual-Haj Osama Diab , Konkati Sarath
Published: November 2020

ADNOC Onshore is operating Habshan gas production field on behalf of Abu Dhabi National Oil Company (ADNOC). The gas reservoir production zones were developed under different project phases. The field has 250 gas (production and injection) wells, which are placed and located in approximately 1200 square kilometers. All gas wells are designed to have SCADA system to monitor, operate and control the wellhead control systems.

Current practice within ADNOC Onshore is to carry out monitoring for Cathodic Protection (CP) of well casing and Chemical Injection (CI) surveys on quarterly basis, this is carried out by mobilizing entire crews physically (visiting every single location) and reporting findings/conditions in order to carry out preventive maintenance and necessary repairs.

The aim of the project is to establish a remote monitoring system utilizing the existing Supervisory Control and Data Acquisition (SCADA) setup in order to monitor the applied corrosion controls, CP and CI injection systems. Based on the implemented modification, essential information was collected, intensive review and analysis were performed and revealed that the system is functioning perfectly as per the operation's requirement for both (CP & CI).

This approach forms a vital aspect of the integrity management of the asset by monitoring the effectiveness of the applied corrosion controls, in addition, the implementation will help Operations to optimize resources, efficiently monitor, maintain, and ensure safety of the facilities and its integrity. Moreover, the implemented method will drastically reduce the associated travelling risk, limiting exposure to the harsh environment (Desert) and potential cost saving.
Real-Time Automated Event Detection Framework for Electrical Submersible Pumps
Authors: Nguyen Nam , Subervie Yves-Marie , Chong Jonathan
Published: November 2020

In artificial lift systems, electrical submersible pumps (ESPs) are often closely monitored due to the relatively high costs of unintended shutdowns and failure. ESP surveillance can range from local alarms and trips using simple logic rules, to full-fledged 24/7 surveillance centers with dedicated experts monitoring the pump and well behavior. These experts are tasked with preventing mis-operation to maximize uptime and ESP run life. Although monitoring has shown tangible results in improving overall ESP operation, a major challenge is the ability to scale up the level of surveillance performance required and maximizing the benefits over a large fleet of assets in a cost-effective manner. With the digitalization trend, the amount of sensor data is increasing, and many systems are equipped with three to five alarm states applied to each measurement. In addition, tighter bounds are required to track the desired ESP operating region, but this often results in a very large volume of notifications and threshold alarms that need to be managed as operational strategies and well conditions evolve over time.

A real-time automated event detection engine framework processes ESP downhole, surface, and electrical sensor data to detect and identify potentially harmful patterns as required by the real time surveillance workflow. The engine is fully automated and can operate without any human interaction, adapting itself to each of the wells it monitors. Therefore, it does not require manual fine-tuning of parameters for each of the wells as required by the traditional multi-level threshold alarms method or other approaches such as fuzzy logic weights to capture relative importance. The engine is a plug-and-play engine that can be deployed on the edge or in the cloud. Notably, the engine is robust to noise and capable of discriminating various types of sensor failures, instrumentation noise, and harmful ESP conditions such as low-flow conditions, while reducing false or unnecessary alarms to an acceptable minimum. Engineered with the optimum balance between domain understanding and machine learning, the engine exploits complex correlations between measurements to provide a single diagnosis/output to end users, instead of multiple alarms per measurement as commonly used today. This engine has been extensively tested both offline and in real-time conditions on active wells and has dramatically improved the efficiency of existing surveillance approaches.
Effect of Total Acid Number and Recovery Mode on Low-Salinity EOR in Carbonates
Authors: Uetani Takaaki , Kaido Hiromi , Yonebayashi Hideharu
Published: November 2020

This paper investigates the main reason behind two low-salinity waterflooding (LSW) coreflood tests, that failed to demonstrate promising EOR response; additional oil recovery factors by the tertiary LSW injection were only +2% and +4% OOIP. We suspected either the oil composition (lack of acid content) or the recovery mode (tertiary mode) was inappropriate. Therefore, we repeated the experiments using acid-enriched oil sample and we injected LSW in both secondary and tertiary modes. The result showed that the low-salinity effect was substantially enhanced; additional oil recovery factor by the tertiary LSW injection jumped to +23%. Moreover, it was also found that the secondary LSW injection was more efficient than the tertiary LSW injection, especially in the acid-enriched oil reservoir. In summary, the total acid number (TAN) and the recovery mode appear to be the key successful factors for LSW in our carbonate system.
Challenges and Mitigation of Static and Dynamic Modelling for Single Well Structures, Onshore Abu-Dhabi
Authors: Ebeid Mahmoud , Eriavbe Francis , Al Khatib Mohammed
Published: November 2020

Introduaction

In a newly discovered field in the south east of Abu Dhabi, ten Thammama reservoirs were penetrated using a single well and how accurate an understanding of a reservoir and the uncertainties remaining can be assessed by a single well penetrating an accumulation of Hydrocarbon is a frequent question for companies planning to develop new, small reservoirs. The answer depends on how much data the single well got and the other information available about the reservoir and analogue reservoirs. When it comes to Modelling a reservoir that has only been pierced by one well, the assurance on the robustness of the available information is necessary in order to identify gaps and areas of uncertainty and then seek the means to minimize them.

X-1 well drilled at the Crest of the structure and the location defined by utilizing leatest 3D seismic cube and the total depth 11500 ft RTKB. It was penetrated in the Lower Cretaceous sequence including ten reservoirs which are trapped by 4way dip closure. All the main reservoirs were tested in X-1 well and produced with an oil rate of 370 - 4,370 BOPD (30° - 32° API)

An analytical "Lambda" Saturation Height Function was developed and implemented in order to overcome the absence of MICP data for initialization stage of Dynamic Modelling. Numerous choices made to develop a family of models that represents the range of reservoir possibilities. Uncertainty analysis including Analog Data from nearby fields utilized to rank the range of outcomes and prioritize obtaining additional information.

This paper highlight a case study of a three onshore Abu Dhabi discovered structures addressing mitigations toward the challenges to draw a solid conclusion with single well modelling when it comes for development decision by Stakeholders at later stage. Further, the methodology as applied to the case study in this paper, allows identification of the range of outcomes and ranks the additional requirements, ranging from acquiring new Seismic data to drilling new wells, which guide for the next steps to a management decision to develop the reservoir or not.
Marginal Field Development – Challenges in Fiscal Oil Allocation
Authors: Maheshwari Nitin , Bani Malek Matar , Alseiari Abdulla
Published: November 2020

Economic development of marginal oil fields usually requires utilization of nearby existing processing facilities to minimize Capital and Operational Expenses. However, tie-back of multi-phase well fluid to other existing processing facilities has challenges in fiscal oil allocation among various Shareholders. This paper presents the fiscal oil allocation experience in development of marginal fields, wherein well fluid is tied-back to existing facilities for further processing and export.

Bu Haseer field is one of the marginal field in the offshore concession area of Al Yasat Petroleum Operations Company. Due to low oil production, standalone development of Bu Haseer field was not economical. Therefore, well-fluid from Bu Haseer fields is tied-back to existing facilities at Das Island. During the initial phase of production, well fluid from Bu Haseer field was measured using Multi-Phase Flow Meter (MPFM) prior to tie-back to the existing facility. Fiscal allocation of Bu Haseer oil production was based on MPFM measurement and converting the measured oil flow at operating conditions to stock tank conditions using PVT correlations. However, oil measurement using MPFM does not meet the accuracy acceptable for custody transfer, thereby not realizing the full commercial value of the production.

Measurement accuracy is improved by installing a dedicated separator to partially stabilize the oil, and measure the separated oil flow as single phase using Custody Transfer Meter, complying with API MPMS (Manual of Petroleum Measurement Standards). The separated oil is pumped through Custody Transfer Meter, to avoid flashing across Custody Meter, which would have otherwise impacted its measurement accuracy. To convert the fiscally measured partially stabilized oil to fully stabilized oil at stock tank conditions, a Shrinkage Factor is applied to account for dissolved gases at separator operating condition. Shrinkage Factor is a function of separator operating pressure, temperature and well fluid composition; which could vary during operations as well as with producing life. Estimation of Shrinkage Factor becomes more challenging when production is from multiple reservoirs sources and downstream crude stabilization process parameters vary. A pre-defined algorithm for Shrinkage Factor is configured in flow computer considering all credible operating modes.

Measurement of multi phase well fluid or partially stabilized oil is usually not recognized in the industry for fiscal allocation, mainly due to measurement inaccuracies and uncertainty in estimation of shrinkage. This paper presents Al Yasat operating experience and challenges with partially stabilized oil measurement and methodology implemented for estimating the oil shrinkage for fiscal allocation.
Refinery Digital Transformation: Driving an End-to-End Value Chain Optimization Strategy with AI and Prescriptive Models
Authors: Gulati Harpreet Gulati , McMullen Joseph McMullen , Awad Mohamad
Published: November 2020

Objectives/Scope: Please list the objectives and/or scope of the proposed paper. (25–75 words)

The intent of this paper is to recognize and address the challenges that downstream companies face across their value chain including a history of having siloed businesses processes that have created ‘value leaks’. We propose an unified operations management approach that orchestrates all activities across the value chain as part of an enterprise digital transformation strategy. Business process can be deeply transformed when operations, supply chain and process optimization are connected in a collaborative environment.

Methods, Procedures, Process: Briefly explain your overall approach, including your methods, procedures and process. (75–100 words)

Refineries are at different stages in their digital transformation journey and have built their business workflows over many years across multiple point solutions.

We propose a digital transformation strategy for operations across five key characteristics, that is:

Results, Observations, Conclusions: Please describe the results, observations and conclusions of the proposed paper. (100–200 words)

Across a refinery's value chain there are significant benefits that can be realized by approaching digital transformation across their operations enabling end-to-end value chain optimization including:

Novel/Additive Information: Please explain how this paper will present novel (new) or additive information to the existing body of literature that can be of benefit to and/or add to the state of knowledge in the petroleum industry. (25–75 words)

This paper is novel as it takes a wholistic look at a refinery operations value chain and eliminating existing value leaks end-to-end. It recognizes how existing systems have been built-up on outdated technology and siloed business process and proposes a path forward bringing operations, supply chain and process optimization together as a key element of a digital transformation strategy. The paper also explores how AI & prescriptive models pave the future for optimization.