bluuebunny/crossref_metadata_2025 huggingface dataset:
Building ADNOC's Pillars for Process Standardization and Best Practices through an Integrated Reservoir Management Framework
Authors: Al Marzouqi Mohamed A. , Bahamaish Jamal , Al Jenaibi Haitham , Al Hammadi Hamdan , Saputelli Luigi
Published: November 2016

UAE has one of the largest portfolios of reservoir development projects across the world. In managing such projects, ADNOC and its operating assets make multiple decisions to optimize production and recovery factor, by selecting the most adequate exploitation plan including among other, reservoir drainage architecture, production allowables and injection distribution. Reservoir management involves the monitoring, analysis and decision making to optimize business performance results and indicators.

ADNOC has envioned strategic goals of reaching sustainable production targets while ascertaining quality assurance through consistency and standardization and by applying best practices. To achieve these strategic goals, ADNOC also identified the following needs, namely: (1) protect the intellectual capital of the workforce (2) train and deploy the growing young workforce faster and consistently, (3) generate the blueprint for consistent workflow execution and (4) provide the platform for expert knowledge sharing and best practices. To achieve these objectives, ADNOC has embraced a framework named Integrated Reservoir Management (IRM) as one of the key management best practices.

IRM is a collection of building blocks, processes, and workflows from surveillance strategy to opportunity generation and execution monitoring. The framework also delineates a set of measurements that allows monitoring of reservoir performance management in the operating assets. It also provides a firm basis for connecting the company strategy with those cross-disciplinary processes and workflows in its day-to-day operations. World-class reservoir management processes include the optimum planning and utilization of reservoir surveillance activities, proper data and information integration to reveal reservoir opportunities, proactive decision making and continuous monitoring of performance.

In this paper, we discuss the experiences in implementing IRM across ADNOC operating assets during the previous two (2) years. The project started identifying current (or as-is) processes used in the operating companies (OPCOs) and across International Oil Companies (IOCs). Based on the analysis of multiple processes in OPCO, a framework of 6 blocks, 18 processes and 29 workflows was developed.

As a result of implementation, IRM framework has allowed sharing standard reservoir management workflows with the added benefits of (a) shortening learning curves to new employees, and hence reducing the total cycle time, resulting in increased productivity, (b) measuring KPI's that cultivate proper behaviors to integrate the right multi-disciplinary efforts in delivering consistent results and (c) fostering a new culture that continuously challenge status quo with consistency.
Application of Ball-Drop Technology to Improve Efficiency and Stimulation of Limited Entry Completion Systems
Authors: Oberhofer Rob
Published: November 2016

Ball-drop or ball-activated completion systems for multistage hydraulic fracturing are designed to reduce stimulation time and improve efficiency by being pumped in one continuous operation. Actuation balls are used in these systems to activate sliding sleeves and internally isolate the production liner into individually isolated stages. While this technology is traditionally associated with single point entry stimulation (one ball per sleeve), advancements in ball-drop technology have led to the development of a system that uses one ball to activate multiple sleeves, combining the efficiency of ball-drop completions with the placement accuracy of limited entry stimulation in cemented liner completions.

Limited entry ball-activated completion technology has evolved over time. Each iteration has been designed with fewer components to further improve the operational efficiency of having one ball activate multiple sleeves in a treatment zone. The latest advancement in this technology has seen a 40% reduction in the number of components, which in turn reduces operational risk. While limited entry ball-drop completion systems have been run for over a decade in openhole applications, the newest version was specially designed to run in a cemented liner application.

The latest version of limited entry ball-activated completion systems is designed to stimulate a high number of entry points in one treatment more effectively, reduce overdisplacement, reduce completion time, remove risk of wireline and coiled tubing runs, eliminate the need to millout the system prior to flowback, and solve entry point erosion concerns. Each port or sleeve is designed to have its own back pressure or limited entry effect (equivalent perforation pressure), which is customizable for each application. By using a non-erodible material in each sleeve the limited entry effect is designed to be consistent throughout the entire stimulation. This is a significant improvement over existing limited entry tools and plug-and-perf completion designs and will lead to more effective distribution throughout the entire stimulation.

In each field trial to date using the new limited entry ball-drop completion technology, all the sleeves have opened and stimulation treatments have been delivered as designed. In the cemented liner applications, the limited entry ball-activated sleeve system allowed stage to stage transitions without shutting down pumping operations.

Limited entry ball-drop completion systems provide instant time and operational improvements to traditional cemented liner completion methods. These time and cost improvements can significantly reduce total well costs, which is especially important for operators in low price commodity environments.
Oil and Gas Co-Development of a Giant Offshore Carbonate Reservoir with Gas Cap: Feasibility Study and Expectations
Authors: Ben Sadok AbdelAziz , Koeck Charles-Henri , Abudaqa Anas
Published: November 2016

Development of Giant carbonate reservoir considerable cap gas and condensate reserves along with oil rim is now being considered as one of the on-hand options to overcome shortage of gas in the long term and to add value to the company assets. This paper presents an overview of the study that was initiated to assess the feasibility of the simultaneous development of gas and oil and to evaluate its impact on the existing oil long term development plan.

A compositional simulation study has been conducted by adding the co-development of the gas cap on top of the current Long Term Oil development plan. This development includes water injection at the original gas oil contact level to isolate the gas cap and to enable to develop gas cap independently from the oil rim. In this scenario, drilling of producers in the gas cap is considered and condensate is produced to the dedicated production system. Several prediction scenarios have been investigated to set up a development plan of gas: Blow down or natural depletion,Produced gas recycling,Lean gas recycling.

The best scenario has then been selected for further optimisation. (On gas injection recycling ratio, project start-up timing, gas production target, and water injection).

After analysing the results, it was found that the blow down of the gas cap provides a good recovery of gas and condensates but has a negative impact on oil reserves.

Gas recycling option proves interesting as it maintains pressure both for condensate (hence preventing drop-out) and for oil; therefore impact on Black-Oil recovery becomes minor.

Oil recovery is higher with late starting time of the co-development or with high recycling ratio. Oil Recovery Factor depends mainly on the pressure maintenance of the reservoir. However excessive gas injection has a negative effect due to breakthrough of the gas into the oil producers which have GOR limit constraints.

Co-development simulation study of the gas cap along with oil, through an inner ring of water injection at gas oil contact shows that the co-development is not only feasible but it will also bring significant value to the company future business plan. Gas cap being semi-isolated from the oil rim, the impact on the oil development plan is minimized.

Co-development proves appealing to the different owners of the field since it brings more gas and LPG that is foreseen as valuable source of enriched gas for later EOR or WAG schemes
Modelling Shale Gas Flow Using the Idea of Apparent Dynamic Permeability
Authors: Farid Syed Munib , Killiugh John E.
Published: November 2016

The basic idea behind this research is to propose a work flow to model gas flow in numerical simulators, which would take into consideration all the complexities of the multiple porosity systems that exist in shale matrix and the different dynamics of flow involved within them. The concept of a multi porosity system that is composed of the organic part (kerogen), inorganic matter and natural and hydraulic fractures is used here. Kerogen is very different from other shale components because of its highly porous nature, capability to adsorb gas and abundance of nano-pores on its surface.

Some theories had been forwarded for the physics involved with gas flow in shale on a micro scale level. However, when working with reservoir scale models, the details as described for porosity systems in micro scale models is lost. To overcome this problem, the idea of dynamic apparent permeability, which is a function of matrix pressure, is introduced in this work. It helps in up-scaling the particulars of the micro scale model to a reservoir one and aids in modelling Darcy flow, Fickian diffusion and transition flow in between the matrix and fractures.

Our assumptions are validated by working with the case of a multi-stage hydraulically fractured horizontal gas well producing from the Barnett shale formation. Exisiting simulation model for this well doesn't take into consideration the relevant flow phenomenon and is used as a base case. History matching after integrating diffusion and desorption, with 7 years of production data, into model reveals that considering these additional processes impacts the assumed SRV region - affecting its volume as well as its properties. This is a critical factor in optimizing completion design, to lower down the well cost for same or even greater production.

We summarize our findings from production forecasts that matrix contribution towards production is under estimated when relevant assumptions for shale are not modelled. This signifies the importance of better understating the transport phenomenon occurring in shale, which would enable us to have a greater insight to scrutinize production data and later to predict changes in production as completion methods are changed. Similarly, this can play a vital role in well spacing for effective field development. This means that a multi stage high density fracturing job might not optimize the well in terms of its value. Decreasing our expenditure on well completions, such that their design results in lower production rates at the initial time period along with lower decline rates, would enable us to produce these wells longer for the same recovery. This would enable us to push the production in future where oil and gas prices might be better.
Advanced Comprehensive Logging While Drilling Dataset for the Evaluation of Low Resistivity Pay Acquired in a Complex Geometry Well of the Nam Con Son Basin of Vietnam
Authors: Das S. , Orr M. , Nguyen V. H. , Diaz E. , Dung L. C. , Hyok J. J.
Published: November 2016

Multi-component resistivity and borehole image logs are commonly used for evaluating low-resistivity laminated sand-shale reservoirs. Stoneley permeability may also be added to help with testing and completion decisions. However, acquiring a comprehensive wireline dataset in a complex J-shape well is extremely challenging. This case study, from the Nam Con Son basin of Vietnam, describes a workflow to effectively use a dataset acquired while drilling to identify and evaluate these low- resistivity reservoirs.

A complete suite of logs, comprising gamma-ray-density-neutron-resistivity-acoustic-resistivity image, was acquired while drilling. The propagation resistivity was processed to obtain horizontal (Rh) and vertical (Rv) resistivities. Laminated Sand Shale Analysis (LSSA), using these inputs, was used to determine the hydrocarbon saturation over the thin beds, and to calculate net pay. A high-definition image log was used to identify the laminated section, and net sand was calculated from this using a threshold technique. The result was compared with that from the Thomas-Stieber method, which also provided shale distribution. Acoustic permeability was also derived using the attenuation of Stoneley wave amplitude.

The conventional resistivity of the thin-bed reservoirs in this basin is generally lower because of the presence of conductive shale layers. Consequently, the conventional formation evaluation approach using these resistivity values resulted in high-water saturation and a small net pay, which did not provide enough justification for a detailed testing and completion plan. The propagation resistivity data was therefore processed using an array inversion technique to provide vertical resistivity (Rv) which is less affected by the laminated shale (Meyer 1998). A high anisotropy (Rv/Rh) was observed against the hydrocarbon-bearing laminated intervals. Using this elevated resistivity in the LSSA method resulted in 52% of additional net pay. The laminar sand volume from the borehole image provided a similar result to that of the Thomas–Steiber and tensor methods, boosting the confidence of the calculation. Permeability calculated from the Stoneley wave, and additional net pay from LSSA, provided adequate information to develop the testing plan which was later pursued. The high-definition image log helped to select the best possible sand layers for testing and sampling.

A comprehensive dataset is required for thorough evaluation of thin-bed, low-resistivity reservoirs, but sometimes the complex well geometry hinders the acquisition process. This case study shows that the suitable data set can be acquired while drilling, and using the resistivity anisotropy along with acoustic permeability and image log can provide detailed information for effective evaluation of these formations.
Characterization and Quantification of the CO2 Sequestration Potential of a Carbonate Aquifer in Falaha Syncline, Onshore Abu Dhabi
Authors: Temitope Ajayi , Gomes Jorge S. , Al Kobaisi Mohammed , Hu Jialiang
Published: November 2016

The capacity for the storage of carbon dioxide in saline aquifers remains enormous. Of all geological storage media, it provides the best storage capacity. In this study, the potential of the Shuaiba Formation, in the Falaha syncline, for geologic sequestration is assessed. A regional geo-model was built using seismic and well data (logs, cores) from the Falaha Syncline and nearby fields. The model was built to honor the heterogeneity and sequence stratigraphy of the Shuaiba carbonate platform using a five-order hierarchical conceptual model of the Shuaiba formation that merged sequence architecture and reservoir architecture together. This was achieved by honoring lithofacies, facies association packages and rock types in their corresponding depositional settings in the sequence framework. Dynamic simulations were then conducted on an upscaled geological model using a compositional reservoir simulator to determine its storage and flow capacity, plume migration pathways and to understand the physics of the fluid flow in the aquifer. Simulations are made to be conservative thus accounting for structural/stratigraphic, solubility (dissolution in resident brine) and residual trapping without accounting for the slower mineral trapping process. Detailed sensitivity studies were conducted during the simulations to understand the effect of well parameters, rock and fluid properties amongst others on the storage capacity in the aquifer. Simulation results indicate that significant volumes could be stored in the aquifer and could take a significant amount of time before the injected gas reaches the surrounding hydrocarbon producing fields. This study provides the first full field approach to characterize and to quantify the suitability of the identified aquifer for long term storage of carbon dioxide in the subsurface of UAE.
Bench-Marking Different Risk Based Inspection RBI Approaches for Inspection Costs Optimization
Authors: Giridhar Y. V. , Manuel J. C. , Al Abri A. M.
Published: November 2016

GASCO has Risk Based Inspection methodology implemented for optimized inspections. The present methodology is based on semi-quantitative approach to calculate Criticality ranking and mitigate risk with the aim to prioritizing inspections. Also to move away from time based inspection to risk based Inspections to minimize risks ALARP (As Low As Reasonably Practical) level.

With improvements in RBI methodologies and better understanding type and rate of damaged mechanisms, inspection intervals become more dependent on the risk and equipment condition.

Following the start in May 1993 of the RBI JIP (Joint Industry Project) managed by API and sponsored by major refining and petrochemical members such as Amoco, BP, Chevron, Conoco, DOW, Exxon, Mobil, Saudi Aramco, Shell, Texaco, a decision was taken by GASCO management to initiate the implementation of its own Risk Based Inspection program.

GASCO RBI pilot exercise was successfully performed in October 1998 at the Bab Plant, in the very early days when this novel concept was just giving its first steps in the Oil & Gas industry worldwide, for refreshing the conventional time-based inspection planning process.

It all started with a relatively simplistic qualitative model developed by GASCO shareholder Shell, which, due to its successful implementation across the industry, rapidly evolved to a more complex but also more technically consistent semi-qualitative model, which was supported by a proprietary database management software branded S-RBI.
Managing the Oil and Gas Talent Equation: Location, Skill and Commitment
Authors: Speers A. , Henchy A.
Published: November 2016

‘People provide the only sustained competitive advantage in the knowledge economy. How can HR and line managers respond to cost cutting calls whilst protecting their company's edge?’

The downturn in the global oil price which began in mid 2014 has had a significant impact on talent acquisition by companies across the oil and gas industry – operators, service companies and others.

In this paper, we will explore how the oil and gas industry – upstream, midstream and downstream - is currently sourcing talent in the Middle East and North Africa (MENA) region, employee sentiment under the current oil price context, how the recruitment sector has adapted during the downturn to meet changing client needs, the talent need in post-sanctions Iran and the main challenges and opportunities – and solutions – facing HR managers seeking to maintain a competitive edge.

The paper will cover the following key themes:Candidate sentiment in MENA in the face of the oil price downturn. How is your most important resource feeling right now and why?Expatriates vs. local content – squaring operational needs with regulatory requirements. Where are expats coming to MENA from? Which local candidates are in good supply and where are the shortages?New markets that offer International Oil Companies (IOCs) opportunities during the downturn such as Iran – the talent need post-sanctionsThe recruitment sector response – increasing specialisationThe key issues and opportunities facing people managers in companies like yours
Standardizing Reservoir Management Best Practices: Lessons Learned from an Innovative Approach in KOC
Authors: Capello M. A. , Dhote P. , Al-Shammari H. S. , Al-Maraghi E.
Published: November 2016

Sound reservoir management practice aims to maximize economic recovery while smartly reducing capital investments and operational costs, optimizing the utilization of technology and talent. Nevertheless, such a conceptual approach, seemingly linear and focused, is challenging in large corporations, for the numerous reservoirs that are produced at different stages of maturity, by a variety of teams.

This is the case of Kuwait Oil Company, the main oil operator of the upstream sector in the State of Kuwait. After more than 67 years of commercial oil production, the company has evolved into a large and complex organization composed by assets and support groups. Incrementally, the need of standard practices of Reservoir Management (RM) is evident, to maximize the optimization efforts at corporate scale.

As an unprecedented initiative, Kuwait Oil Company (KOC) engaged in a journey of standardization of its RM practices, to manage with top standards its more than 142 oil and gas fields on the inland territory of Kuwait. The initiative comprises a two-fold effort: A formal project led by KOC's RM Team, to identify and assess the status of RM Practices in KOC;A Steering Committee of executive level, charged with the implementation of standards policies, guidelines, and workflows for RM.

All Assets in KOC are already benefitting from this approach, as the initial results from the assessment of the current status of Reservoir Management Practices, have established the good practices, as well as the tools and techniques to be massified. At the same time, the identification of existing gaps in Reservoir Management Practices was completed, establishing a clear plan to minimize them. The acceleration of the uplifting of KOC's Reservoir Management (RM) processes, will need a sound governance model for the implementation of the RM policies, grounded on the findings established and customized to the corporate organization and goals of KOC. The achievement of short- and mid-term goals has started, with the PIP (Process Implementation Projects), aimed to enable important improvements of RM in all oil and gas Assets of KOC.
Enhancing Risk Management Process on Rigs through E-JSA
Authors: Devnani Girish Kumar , Dash Deepak Kumar , Salem Muneef , Salama Mina Aziz
Published: November 2016

As Drilling industry continues to bring-in more complex systems and new generation rigs, it is becoming increasingly more difficult to carry out Job Safety Analysis (JSA). Hazard and corresponding control systems identification put in front noteworthy problems as hidden and complex hazards are not easy to identify and corresponding controls sytems should match with and counter the potential severity of hazards. To respond to these issues, there is an increasing requirement of SMART automation of Job Safety Analysis.

This Paper describes the components of electronic Job Safety Analysis (e-JSA) system and how ease of personnel interaction with the system has led to the output of more systematic and authentic Analysis of Hazards and Control assignment at rig sites; enhancing the JSA quality to much higher level and thereby resulting in reduction of Incidents/Accidents.

Methods, Procedures, Process

With the introduction of e-JSA, NDC has gone that extra mile in managing the JSAs across rig sites. This system guided step by step approach ensures that potential hazards and consequences are not missed out thereby increasing safety aspect. This new system delivers unparalleled benefits like capturing of JSA at the rig site with details of the operation type, activities, IPM, PPEs, responsible persons and authors involved for the JSA. Submission, review, approval and evaluation process is fully automated along with authorization control ensuring speedy approval and getting rid of paper document circulation with complete traceability at any given point of time.

Novel/Additive Information

NDC HSE commitment and quest for innovation is further supplemented by e-JSA system. NDC is has already taken initiative to take the e-JSA system on the rig floor, so that the JSA can be opened & discussed by the entire team before commencement of any job. Based on the success of e-JSA system, a Proof Of Concept is in progress which after implementation will facilitate the rig crew on the rig floor to access the JSA documents from rig floor itself.

We are exploring the option to transfer the same software for Risk Assessment with minor modifications such as changing terms like ‘Hazards’ to ‘Risks’, ‘Hazard Categories’ to ‘Risk Types’ etc. By Q4 of 2016, we are targeting to demonstrate the e-JSA system to other ADNOC group companies. On successful completion & positive feedback of the e-JSA system over the last 2 years of launch, we have started automation of most of the processes pertaining to HSE.
Re Engineering of Training to Success
Authors: Ali Adeib
Published: November 2016

Objectives/ Scope

The performance of the Training unit was on the decline despite increase in allocation of manpower and additional funds during the previous couple of years despite induction of fresh blood and benchmarking across sister companies. Similar tendencies were observed in some companies across the industries. This resulted in the restructuring of the unit by movement to a new division and with increased immediate focus led to automation of a few processes and improved performance but still resulted in continued gaps between planned and achieved figures. The resultant loss of learning opportunities led to introspection of existing processes, procedures, activities, RACI matrix etc. It was decided to bring in fresh ideas and explore new concepts which were not used across the group of companies hoping to be a role model whereby we can share the success in future once achieved.

In 2015, there was a call by Senior Management to optimize costs and the decision was to curtail a few of the training sessions that were deemed comparatively less critical to Business Continuity after consultation with the line. The spare time available to the Training unit members were utilized creatively to undergo courses in ISO Lead Audit & 6 Sigma. Upon return, as a proactive measure – employees decide to lead the objective in implementing Quality Assurance and Control measures that could help in identifying wastes or leakages in productivity and then on to proceed with implementing measures to enhance performance.

ISO 29990 was specifically considered as it was a specific standard for Learning Providers and was unique to the region unlike ISO 9001 standard which is generic and common. None of the sister concerns or any other company in the oil and gas industry at that time functioning in Abu Dhabi had achieved the accreditation in the same. However, the quality enhancement mechanism in this standard was left to each company and the decision was taken to explore 6 sigma options along with other TQM tools to be implemented by 2016. A task force was created to proceed with implementing the same with the additional objectives of handling monitoring as well controlling issues along with exploring future options in 2017 once the same has been achieved.
Sustaining High HSE Performance by Effectively Transforming Data into Information - the Al Hosn Gas Integrated HSE Database
Authors: Krishnamoorthy Prakash , Boardman Benjamin N.
Published: November 2016

Al Hosn Gas Executive Management saw the benefits of an integrated solution to managing Health, Safety and Environment (HSE) data aligned with the other Company business processes and using the same core data e.g. locations, terminology and key database tables to ensure a comprehensive strategy of centralised data management.

The new SAP Environmental, Health and Safety Management (EHSM) Modules are Incident Management, Risk Management, Waste Management, Environmental Compliance, Audit, Sustainability and Performance Measurement and Action Tracking.

Each ESHM module has an integral action tracker. Once entered actions are tracked and expedited automatically through the systems workflows (defined for each module on an activity by activity basis). The range of subject matter covered by the SAP EHSM modules surpasses the limitations of procuring individual specialist packages that do not share data without certain user manipulation. Within EHSM specific data can be downloaded to a variety of formats including Excel, Word, Pdf etc. and used in whatever software is required.

A substantial effort was dedicated to ensuring the system satisfied the requirements of the ADNOC CoPs and contained enhanced features. The system went live in 2015 and has been recognized throughout the company as a great success that’s adds considerable value to the organization.
Challenges & Opportunities in Implementing an Integrated Asset Operations Model IAOM in Mature Field
Authors: Das Rupa , Salem Salem El-Abd , Hafez Hafez H.
Published: November 2016

The objective of this paper is to present the challenges & opportunities in implementing an Integrated Asset Operations Model (IAOM) for a super giant field. Conclusions of this paper are drawn based on an actual project that prepared an interactive production and injection network system to accurately simulate the overall system from completion intervals to export point in a super giant field of UAE discovered in ′60s.

The subject super giant field has now crossed a life span of 50 years. As this field was built around the technologies of ′60s and ′70s, any efforts to develop infrastructure failed to keep pace with evolving technology. In addition incremental benefits of asset model were perceived to be marginal over huge business impact of supply interruptions, expensive brownfield modifications, and effort required in retrofitting. However continued focus on improving operating efficiencies has slowly begun to change the way organizations respond to their production optimization & surveillance needs.

This field is producing from carbonate reservoirs and the remaining producing life of the field is expected to be another 50 years. It has over 600 wells which include oil producers, water & gas injectors, water supply & disposal wells along with large oil processing plants, and water injection clusters. The subject field's journey toward having IAOM tool started in a modest way in 2012 when the management wanted an integrated solution to optimize production, identify and remove bottlenecks, artificial lift selection, linking reservoir simulation models, managing production & injection allocation forecasts, and last but not the least, managing operational downtime. Higher production rate, and larger remaining producing life coupled with big infrastructure made it a perfect candidate for implementing an IAOM solution.

This paper highlights how the asset selected a fit for purpose IAOM solution, developed the solution over time, overcame challenges in planning & execution, and realized benefits of initiative. Amongst the main challenges were ageing infrastructure, integrating & consolidating information, and overcoming organizational resistance to change.

In a nutshell, the implementation of IAOM solution presented unique sets of challenges & opportunities in every field. It was observed that when it comes to mature & super giant fields with complex organizational structures, these challenges only multiply. In addition to justifying the capex involved in hardware & software, the decision makers also have to plan for operational, organizational, process & information challenges that could be more difficult to solve. Amongst the main benefits from IAOM implementation is integration, standardization, and improved operational efficiencies. This paper will be a useful reference in situations where decision makers face dilemmas of choosing between businesses as usual approach over IAOM in mature fields.
First Expandable Liner Hanger Installation in United Arab Emirates in HP/HT Well
Authors: Ragsdale Eric , Mohamed Zeid , ElSin Rami Samir , Monneyron JC , Roy Christophe
Published: November 2016

This paper discusses the planning and deployment of an expandable liner hanger (ELH) system in an offshore high pressure/high temperature (HP/HT) well for the first time in the United Arab Emirates (UAE).

New technologies and methods were used to quickly and reliably drill and complete the HP/HT well.

The technological advances of ELH systems have increased well life and improved safety during liner installations globally compared to traditional systems. Sealing capabilities with expandable systems have evolved beyond conventional tools and the smooth radial flow paths, allowing for greater ease of installation. A series of redundant sealing elements provide a gas tight liner top seal, which helps prevent possible gas migration. Also, with the ELH system, rotation and reciprocation while cementing are possible.

The result shows consistent material cost savings, reduced installation time, improved reliability, and increased versatility compared to the conventional liner hanger system or a casing to surface design.

During well design, the service company proposed use of an ELH to the operator for large casing sizes (16 in. inside 20 in. and 11 3/4 in. inside 13 3/8 in.) to help reduce rig time and material costs for the HP/HT offshore well. This was critical to the project time and material costs.

Design and preparation were challenging for this well, particularly during the assembly and make up of this large sized liner hanger in the UAE. The system was assembled, inspected, and tested using the service company's workshop and an approved third-party shop, when needed.

Selecting and securing drillpipe for liner running operations was challenging because of the heavy weight of the 16-in. liner. The service company and the operator worked together closely and located the necessary heavy weight drillpipe from a third-party supplier in the UAE.

The running operation was also challenging because of the liner hanging up at numerous points during installation. However, because of the robust capabilities of the ELH system to rotate, reciprocate, and support a high rate of circulation, the liner cleared all hang-up points.

This paper elaborates on common operational problems encountered while running liner hangers offshore and how the ELH technology overcame said issues.

This paper also describes issues faced in terms of liner deployment in HP/HT wells in UAE waters and a reliable solution that saved time and material costs.
Identification of Thief Zones and Water Allocation in Dual Water Injectors with Temperature & Spectral Noise Logging
Authors: Sarsekov Arlen , Al-Neaimi Ahmed Khalifa , Zhao Wenyang , Saber Mohamed , Tauk Raj , Volkov Maxim , Makhiyanov Ruslan , Barghouti Jamal , Vishnu Raveen
Published: November 2016

The problem of evaluating injection profile in Short Strings (SS) in a dual completion wells has been solved. The HPT/SNL combination to describe accurately and economically the injection profile within the borehole and behind pipe through long string will be demonstrated.

It is difficult and cost prohibitive to monitor injection in a dual completion. Because of this, injection with such completions often goes unchecked for years, wasting water, making wrong assumptions in reservoir performance and missing opportunities for effective water-flood management. Conventional production logging cannot be performed in Short String due to accessibility and are unable to determine the injection profile, therefore, advance tools are required. The objective of this study is to demonstrate how the HPT-SNL logs, run riglessly in the Long String(LS) only, track flow geometry and assess completion integrity.

The well WI-01 was re-completed as a dual water injector in Unit C and Unit D in SS and Unit F in LS in 2005. Due to several unresolved issues with well performance, it was decided to confirm injection distribution, determine any communication between the strings and check for cross-flows behind pipe. HPT/SNL in combination with standard production logging tool was run to meet the objectives reliably at minimal cost. Three logging runs were made in the Long String: First, with both strings shut-in, second with injection into SS and third, both string shut-in to measure transient responses.

The integrated response of High Precision Temperature (HPT) and Spectral Noise Logging (SNL) indicated Unit C and Unit D were active as expected. Additionally, HPT-SNL combination identified a thief Zone (Unit B) in a non-perforated interval contributing to injection. Injected water was observed flowing upward behind pipe between Unit C and Unit B even when the well was under shut-in condition, indicating cement failure.

The survey revealed no communication between the two strings, whereas minor injection was evident below the surveyed interval. The results from this survey will lead to injection optimization in both strings to increase ultimate recovery.
Key Tool for Production Optimization in Low Oil Price Environment- A Case Study on Integrated Asset Operation Model IAOM
Authors: Al Selaiti Iman Hamad , Al Haj Jassim Mohammed , Ranjan Kumud , Soni Sandeep
Published: November 2016

This paper describes an efficient approach to implement IAOM project and evaluate subsurface well performance and surface network facilities of a supergiant oil field flowing from multilayered carbonate reservoirs. The field is produced via several gathering stations and pumping stations. The current manifold pressures at the RDS stations are high, which will increase by the introduction of gas lift and by the additional production from new wells.

In IAOM implementation process, individual well strings and robust network model was built for the asset on the IAOM platform. This model was further utilized in meeting various production optimization challenges such as well surveillance, production and Injection optimization, forecasting and allocation and field development planning. This paper demonstrates how IAOM project was used to run different production optimization scenarios, describing the objective, methodology, analysis and results to address various challenges in production optimization. Following case studies were carried out for this purpose: Well potential rate analysis and optimization: To determine well potential rate based on the well performance, reservoir guidelines and back pressure in the network system.New producer well tie-in to existing network: To investigate optimal option for a new producer well flowline tie-in to existing well flowlines carrying fluid to remote degassing station and study well flowline performance after tie-in.Wellhead shut-in pressure analysis and optimization: To estimate wellhead shut-in pressure at which well ceases to flow when reservoir pressure is increased to new pressure.New pattern injectors tie-in to existing clusters: To estimate tie-in options for new water injector wells for new developments project to the existing clusters based on availability of water supply and closest distance.
Contracts with Cloud Providers for the Oil and Gas Industry: A Legal Perspective
Authors: Kafeza Irene
Published: November 2016

Oil and gas industry is influenced by the cloud computing era. The urgent requirements for employee safety and social responsibility demand quick and efficient response times thus immediate access to data and processing that can scale up based on the needs in a price effective manner. Due to the sensitivity and the criticality of the information transmitted in the oil and gas industry applications, the clients and the service providers need to customize their agreements appropriately. While standardization of cloud services as well as virtualization can contribute to lower costs of IT infrastructure for the oil and gas industry, still specific details need to be explicitly addressed in the contracts that will guarantee the aforementioned requirements that are very sensitive in this industry. In this paper I am looking into the problem of cloud contractual agreements between clients of the oil and gas industry and the cloud service providers.
Remote Sensing Technologies for Gas Leak Detection, Visualisation and Quantification Using Infrared Imagers
Authors: Xavier Watremez , Labat Nadège , Audouin Grégoire , Lejay Bertrand , Xavier Marcarian , Dubucq Dominique , Marblé André , Foucher Pierre-Yves , Poutier Laurent , Danno Ronan , Elie Damien
Published: November 2016

TOTAL, ONERA - The French Aerospace Lab - and ADCIS companies are undertaking a multiyear R&D collaborative project to develop remote sensing technologies and methodologies for gas leak detection, visualization and quantification. The history of gas leak incidents in the Oil and Gas Industry has shown the need for efficient and accurate tools for quantifying the gas leak rate and the extent of the hazardous areas to manage efficiently an emergency situation. Besides, detection and measurement of gaseous hydrocarbon emissions in industrial facilities is a must for obvious environmental reasons. The current generation of infrared imagers detects the presence of gas in the atmosphere but needs improvement for accurate estimation of the size of the gas leak.

In this context, a test campaign held on September 2015 in TOTAL’s Lacq Pilot platform in France was organised to determine if infrared multispectral or hyperspectral imaging could provide reliable and quantitative data in the event of a release in the range of 1g/s to 50g/s of methane.

Several gas spectral imaging systems were installed to observe a methane emission point:hyperspectral cameras in Long-Wavelength InfraRed (LWIR) (7.7-12µm);multispectral cameras in Medium-Wavelength InfraRed (MWIR) (1.5-5.5µm; 3.2-3.4µm and 3-5µm);multispectral cameras in LWIR (8-9.6µm);one Spectro-Radiometer system in MWIR/LWIR (3µm-14µm).

The performance of infrared imagers in different wavelengths has been compared for methane emissions. A set of algorithms and software has been developed and successfully tested to measure, compute and visualize in real time a methane plume from the infrared imagers, and with reasonable accuracy for the methane emissions of 1 and 10g/s. For the 50g/s flowrate, quantifications have been under-estimated with this methodology. Further works should allow improving the accuracy of these quantification methodologies. The gas imagers enable to visualize and quantify in real time and in 3D a methane plume.

This technology could be applied in different ranges of gas leak flowrates (small leaks in environmental monitoring, medium size leaks in safety monitoring, and major leaks in crisis management). The objective over time is to qualify a system that would economically complement the plant gas detection system and bring valuable information should a gas leak incident happen.
Case Study on Frequent Failure of Dry Gas Seals
Authors: Manikandan Arumugampillai , Moorthy Subramanian
Published: November 2016

Case study on frequent failure of dry gas seal in centrifugal compressor

The process gas high pressure compressors used in oil & gas industries requires highly safe and reliable operating requirement. This case study represents the frequent failure of dry gas seal (DGS) in Re-injection Gas Compressor within 20 Days of previous dry gas seal replacement.

DGS systems are specially designed to seal the process gas in centrifugal compressor. The seal gas is extracted from the discharge of same compressor and supplied to DGS after filtration with necessary control (Pressure or flow) based on the requirement in the seal cavity. Ingression of foreign material into the running gap of the seals leads to degrade sealing performance and eventual failure of the seal. After sealing the process gas, a very small amount of the sealing gas passes through the primary seal faces which are connected to the flare.

In this case study we found sudden increase in primary vent leakage was observed during operation and after investigation it is decided to perform the internal inspection of DGS. Black/brown contaminates were found in seal cavity and DGS cartridge. After cleaning seal cavity the spare DGS was replaced.

After restart, the unit tripped again due to high primary vent pressure within 20days in normal operation. It was decided to disassemble the DGS cartridge again. The same contaminants were found in next inspection. Additionally inspection on DGS panel and piping were checked. ➢Seal gas supply line which was taken from compressor discharge was confirmed as heat traced.➢External gas supply into the dry gas seal during startup and shutdown ensured.➢Found C6+ component percentage higher in the seal gas than the previous gas composition which was analyzed before 5 years.➢The condensation occurs in the seal gas injection line due to JT effect and condensates/liquid drops affects the seal faces of DGS which leads to high leakage in the primary vent.✓Performed DEW Point analysis for the current gas composition and identified the required seal gas temperature.✓The heat tracing was found insufficient to meet the changed gas composition.✓Installed heater (15 KW) in the seal gas injection line after the gas filter to maintain the gas temperature.✓Increased the heat traces capacity from 5 KW to 10 KW in the seal gas injection line.

The gas compositions changes over period of time from the offshore well which requires period analysis (Every 6 months) and monitor the heat tracing system.

This case study is providing the trouble shooting experience and useful information for all the re-injection gas compressors incorporated with dry gas system in oil & gas industry to have more reliability.
Evaluation of the Wettability and the Petrophysical Properties in Carbonate Reservoirs by Advanced NMR and MRI Techniques
Authors: Matenoglou G. , Kelessidis V. C. , Garcia A. P. , Heidari Z. , Fardis M. , Karayanni M. , Maris Thomas G.
Published: November 2016

Carbonate rocks are among the dominant oil reservoir formations. Due to their heterogeneity, their petrophysical properties are difficult to be evaluated. Magnetic Resonance, applied as low-field Nuclear Magnetic Resonance (NMR) or Magnetic Resonance Imaging (MRI), are powerful tools for reservoir characterization. Their basic advantage is the quantitative demarcation of various fluids. In this work we have used MRI methods in order to evaluate the petrophysical properties of carbonate rocks. For this purpose commercial limestone, saturated with deionized water, crude oil and model oil or mixture of water with model oil were used to acquire calculated spin-spin relaxation time (T2) and Diffusion Tensor Imaging (DTI) MRI scans. This leads to the pixel-by-pixel characterization of the rock samples and the quantitative evaluation of the saturation profiles in 3-D space. The proposed MRI techniques offer a new insight in the spatially resolved information of petophysical properties towards better understanding of the fluid-rock matrix interactions.