bluuebunny/crossref_metadata_2025 huggingface dataset:
Erosion Risk Mitigation with DTS Based Monitoring System
Authors: Ravet Fabien , Silva Cristian , Gil Rodolfo , Maguire Simon , Rochat Etienne
Published: November 2020

The article aims at demonstrating that distributed temperature sensing (DTS) using telecommunication cable laid along a pipeline can detect the early signs of erosion. It shows that the technique not only applies to both hydraulic and aeolian erosion, it also allows the localization of the event and the estimation of its severity.

The article introduces the physical principle behind the proposed detection solution. It reviews the heat propagation theory that sustains the approach for any water saturation conditions and soil type. It describes distributed temperature sensing capability and its uniqueness to measure and locate temperature events with meter accuracy. The technique is then validated by analyzing temperature data collected along a Natural Gas Transport System instrumented with DTS. These observations are compared with periodic surveys conducted by the operator integrity team.

FO based geotechnical monitoring is successfully used in operation to detect landslides along the Sierra section of the Peru LNG pipeline since 2010. These natural hazards are not the only ones threatening the pipeline. First, in the Sierra region, it is common to observe severe hydraulic erosion during the rainy season. Second, the coastal section, which is a desert, experiences other phenomenon such as sand dune migration and eolian erosion that put the pipeline at risk. DTS instrumentation measures continuously and automatically the fiber optic communication cable. The analysis of the monitoring data in both regions shows the detection of very localized events. Their spatial and temporal signatures are analyzed. The comparison of these data with thermal models identified sections that are near to be exposed or whose soil cover is less than 50cm over a spatial extension that does not exceed a couple of meters. Depth of cover of 10 to 30cm are estimated from such analysis. These results are confirmed by past and ongoing site inspections.

The successful detection and localization of hydraulic and aeolian erosions and confirm the value of DTS to mitigate geohazard risks. It not only enhances the efficiency of the integrity program detecting and localizing threats, it also improves and rationalizes the maintenance activities as focused surveys can be conducted.
Marrying the Static and Dynamic World: Enhancing Saturation and Permeability Interpretation using a Combination of Multifrequency Dielectric, NMR, and Wireline Formation Testers
Authors: Mostafa Hassan , Al-Jefri Ghassan , Menchaca Tania Felix , Allouti Abdelkader , Bong Saudyono , Cherian Jobin , Dar Usman , Dasgupta Suvodip , Cig Koksal
Published: November 2020

Reservoir characterization is a key element of asset evaluation and optimal field development strategies. Accurate water saturation evaluation and permeability profiling are crucial parameters in determining volumetrics and productivity of the multiple, stacked carbonate reservoirs in offshore Abu Dhabi and derisking the reservoir management process. The main objective of this paper is to look at saturation and permeability interpretations by comparing the various static and dynamic logging measurements.

Archie in 1942 postulated the water saturation calculation equation for sandstones, but it has also been used in carbonates because of its simplicity. Multiple authors have understood the effect of different textural parameters on water saturation calculation and have come up with different workaround techniques. The current case study illustrates how the integration of static measurements, such as dielectric dispersion and nuclear magnetic resonance (NMR) with dynamic measurements improves our understanding of the reservoir properties (saturation and permeability), and in turn support a more accurate reservoir evaluation. Sampling and downhole fluid analysis (DFA) performed by the wireline formation tester (WFT) identifies the fluid and rock properties in the various flow units.

One key observation in this case study is how the conventional Archie-based equation has struggled to provide satisfactory and accurate water saturation results in this reservoir, whereas the dielectric dispersion measurement proves its value by providing direct water volume measurement that is validated with the fluid pressure gradient and the sampling results. The WFT sampling and DFA stations—which account for the flowing fractions and the hydrocarbon characterization—are followed by an extended build up, otherwise known as mini drill stem test (mini-DST). The radial flow regime is used to derive the horizontal/radial permeability across the tested interval. Mini-DST measurements provide a depth of investigation much deeper into the reservoir compared to standard core or log analysis, yet at a fraction of the operational times typically needed by a full drill-stem test. This integration of static (saturations and permeability) with dynamic measurements (DFA and Mini-DST) aids in providing accurate reservoir characterization and better understanding of its properties.

Multifrequency dielectric measurements add a weapon in the arsenal of the petrophysicist and can be used in conjunction with dynamic measurements from the wireline formation tester to understand the rock and fluid properties and get a better understanding of the Cretaceous reservoirs of interest in offshore Abu Dhabi.
Waste Heat Recovery From Gas Turbines
Authors: Al Ketbi Waneya , Sajjad Saqib , Al Jenaibi Eisa
Published: November 2020

In accordance with the corporate drive towards sustainability & 2030 strategy to reduce Green House Gases (GHG) intensity by 25%, ADNOC Gas Processing strives for energy efficiency improvement in its existing and future assets. With the current focus on Waste Heat Recovery (WHR), ADNOC Gas Processing is looking into energy saving opportunities to improve operational efficiency and reduce fuel gas consumption. This paper presents a comprehensive technical assessment including cost benefit analyses of recovering waste heat from mechanical drive gas turbines for energy savings. Earlier a high- level technical assessment was carried out to assess the potential of recovering waste heat from different heat sources across ADNOC Gas Processing plants. Recovering waste heat from mechanical drive gas turbines indicated promising results. Accordingly, a detailed feasibility study was carried out to evaluate several options to recover energy from gas turbines exhaust. The feasibility study addressed three options of recovering energy from gas turbines exhaust; generating superheated steam, generating power and combined solution of steam & power. The options were assessed in terms of technical feasibility and commercial viability. The waste heat recovery potential was assessed for design as well as actual operating data.
First Successful Application of a New Tailored Spacer System to Cure Losses through Coiled Tubing and Plug a Challenging Well in the Largest Offshore UAE Field
Authors: Bezerra De Melo Alexandre , Alaleeli Ahmed Rashed , Benberber Mohamed Rebbou , Jose De Barros Adelson , Baouia Bilal , Medina Ruben , Agapiou Kyriacos
Published: November 2020

Drilling and cementing operations commonly experience lost circulation (LC), which can result in non-productive time (NPT) and excessive costs. Losses were encountered while performing an offshore workover well operation in the UAE that challenged isolation objectives involving spotting a cement plug through coiled tubing. Selection of lost circulation treatments that may be deployed through coiled tubing is limited, increasing the difficulty in addressing losses. Previous attempts to cure losses and spot the cement plug were unsuccessful. This paper describes the application of a new tailored spacer system (TSS), engineered to reduce formation permeability and prevent lost circulation. Placement occurred through coiled tubing to successfully control losses in the thief zone, enable tagging of cement plugs, and achieve isolation for the zone of interest. The new TSS has been used on multiple cementing operations to mitigate losses, improve circulation, achieve top of cement (TOC) objectives, and eliminate remedial work; however, this case is the first global application of the TSS through coiled tubing in a plugging operation to stop lost circulation. Correctly evaluating and interpreting the well conditions, risk identification, analysis, and communication amongst operations personnel, and execution of good cementing operational practices led to utilization of the new TSS for this specific scenario of placement through the coiled tubing ahead of the cement slurry. Losses were prevented leading to a successful plug operation and enabling cementing goals to be achieved.
Assessment of a 30 years Corrosion Management in Oil Producers under Carbon Dioxide Environment in a Giant field Offshore Abu Dhabi Case Study
Authors: Odeh Nadir , Al Azeezi Khaled , Aldhaheri Khalid , Ban Hidarah Talal , Aljasmi Sultan , Almheiri Fatima , Alhammadi Khalifa
Published: November 2020

ADNOC Offshore in 1988 started implementing a corrosion management strategy for Offshore oil field located in Abu Dhabi. A robust Corrosion Management System developed to protect producer wells equipped with carbon steel tubing from sweet corrosion. With water break through many wells were in high corrosion risk, the effective approach provided completion protection to assure well integrity and extended tubing operating lifetime, which saved production and allowed for OPEX and CAPEX allocation. Presented in this case study a thoroughly review for the field implementation, performance, and economic impact.

In addition to cost impact, implementing a strategic solution to replace tubing with Corrosion Resistance Material was challenging for immediate implementation due to the large number of wells with corrosion risk. Moreover, wells initial design did not consider capillary line for continues chemical inhibition system. The only visible solution was to implement corrosion inhibition chemical by squeeze to formation and flow it back with production fluids creating a protective film over tubing wall. This approach required effective monitoring system to optimize priority and evaluate chemical performance. Combing logging and simulation tools and collected data over 30 years present the process performance and value.

In place corrosion management system provided a systematic corrosion protection that is effective and efficient in sweet corrosion environment. Many factors can impact corrosion rate and inhibition efficiency such as, water cut, deviation angle, flow velocities, pressures and temperatures, all contributing to the corrosion process. CIS treatment if applied regularly can significantly mitigate the corrosion process and consequently extend the operating well lifetime.

Implementing CIS regularly dropped the immediate need to replace tubing with corrosion resistance alloy material (CRA), which allowed allocating workover rigs to serve different requirements. Corrosion management system in oil field offshore Abu Dhabi is an important safety tool that protected environment by maintaining well integrity and extending well life up to 30 years, delaying rig operation and optimized recourses. Setting up a state of the art system and saving cost.

This paper, presents a real case study of a comprehensive Corrosion Management system provided a cost saving and safety tool. Expanding the implementation to other fields where water cut started to increase, can provide a cost effective solution against corrosion.
New Training Delivery to Adapt to Millennial Entering the Workforce
Authors: Audrey Beryl , Florez Fabian , Kartoatmodjo Gayatri
Published: November 2020

Despite the downturn in oil and gas industry, the recruitment of young engineers continues to ensure the succession of workforce pipeline. The need of building their competency is critical and hence a systematic training program is required with the emphasis of agility to adapt to any business condition leveraging with the latest technology.

One of the most important skillsets to any graduating engineers and scientists entering the oil & gas industry is to understand fluid flow from the reservoir up to the sales point, starting from a basic well productivity driven by reservoir characterization to surface facilities equipment functionality and specifications. Digital technology has been one of the main enablers of the link to efficiently develop an oil/gas field. An interactive training program is built to combine the theory and practical in a modular format. The program is designed to deliver a practical graduate engineer within 30 to 36 months of hire. The program consists of combination of on the job (OJT), web-based training (WBT), classroom and hands on practical training. One of the main modules is designed to mimic an oil field condition using state of the art digital technology to simulate both subsurface and surface condition. This module is designed to enable engineers to learn actual data, associated with field problems that lead to decision making process in the field.

The overall training experience allows the use of a real facility equipment with minimum HSE risk. The simultaneous reservoir/production model proved that is powerful exposure to build quick basic to intermediate production, reservoir and operation competencies in a controlled training environment.
CO2 – Green Refrigeration for FPSOs
Authors: Adamson Ben
Published: November 2020

FPSOs usually require refrigeration, for removal of condensates and/or water before export of produced gas, or for treatment of gas to be used on board as fuel gas. This paper describes on-board refrigeration using a new combination of different concepts, none of which individually are new, to deliver refrigeration for FPSOs with environmental, cost, space and weight advantages.

Usually, FPSO owners specify a non-flammable refrigerant, and most current applications use R-134a refrigerant. However, R-134a is a hydrofluorocarbon with high global warming potential (GWP = 1300). These high-GWP refrigerants are being phased out under the 2016 Kigali amendment to the Montreal protocol, and are already banned for new applications in many European countries. Low-GWP alternatives to R-134a include hydrocarbons such as propane (GWP = 3), ammonia (GWP = 0), hydrofluoroolefines (HFOs) and CO2 (GWP = 1). HFOs are new synthetic refrigerants with GWP generally <150, but are flammable, though less flammable than propane.

CO2 was widely used as a refrigerant up to the 1930s, particularly in marine applications, but was superseded by early synthetic refrigerants such as R-12 and R-22, which were then phased out in the 1990s after discovery of ozone depletion effects. CO2 is limited in air-cooled applications at high ambient temperature conditions such as tropical climates, due to the high-pressure side of the system becoming supercritical, leading to high operating pressure and low efficiency. However, FPSOs mainly operate in deep water, and even where surface water temperature is high, say +30 deg.C as in the tropics, cold water below +20 deg.C, can be found at depths of 100-200 m, even at the equator. Use of cold seawater via deep inlet risers is already used for some other FPSO applications, and if used for cooling in CO2 refrigeration systems, the system can operate at subcritical conditions, power becomes competitive and an optimised CO2 refrigeration system can have lower power, smaller footprint and lower weight, compared to a similar optimised R-134a refrigeration system.

CO2 is now a viable refrigerant for FPSOs, with environmental, cost, weight and operational advantages over R-134a. Using CO2 as above is a new combination of known concepts, none of which individually are new, to achieve a new and better refrigeration outcome specifically for FPSOs. It is not a proprietary technology of any company.
Optimizing Production from Marginal and Challenging Prospects to Unlock Field Potential: Success Cases in the Jasmine Field, Gulf of Thailand
Authors: Yusuf Mukminin , Prasongtham Pattarapong , Limniyakul Theeranun , Nuada I Nengah , Kulchanyavivat Sawin , Laoroongroj Ajana , Dachanuwattana Silpakorn , Watcharanantakul Rattana
Published: November 2020

The development of marginal volumes in the Jasmine field is part of Mubadala Petroleum's overall strategy to extend the field's life. This development is accomplished by progressively exploiting increasingly challenging prospects. This paper highlights two case studies to illustrate how Mubadala Petroleum has successfully developed marginal prospects to unlock the Jasmine field's remaining potential.

Prospect identification begins with integrated subsurface studies focusing on contingent resources. Several studies were conducted to determine the right technology to mature these marginal prospects. These prospects often involve the requirement to drill Extended Reach Drilling (ERD) wells. This is due to the fact that some platforms are slot constrained, such that wells cannot always be drilled from the nearest platform.

One of Mubadala Petroleum's solutions was to drill a horizontal well with a completion that uses an Autonomous Inflow Control Device (AICD) to optimize and enhance oil production. This combination of AICD and ERD horizontal wells has proven successful in the Jasmine field's continuing development.

Two wells in this case studies were drilled during the 2018 and 2019 drilling campaigns, illustrate how marginal volumes are developed in the Jasmine field, with each case having unique objectives and challenges.

In 2018, one horizontal well was drilled, with an aim to enhance recovery efficiency in the viscous oil reservoir. The well was drilled close to the top reservoir, AICD devices were installed in conjunction with a sand screen to delay water breakthrough, and the well has been in production for two years. The overall strategy was effective in delaying water breakthrough.

In 2019, a horizontal well was drilled to develop a relatively small 14ft oil rim below a thick gas cap reservoir. This well was the longest ERD well in the Gulf of Thailand. The well was also successfully drilled and geosteered at 4-5 ft TVD below the gas cap. AICD's were installed to balance the gas cap expansion and aquifer support to optimize oil production. The well has produced at a stable oil rate of 500-600 bbls per day with minimal gas and water production, up to the present date, confirming the validity of AICD technology in reducing the production of unwanted fluids.

The AICD has been shown to play a significant role in optimizing production in reservoirs with small oil rims and thick gas caps. AICD completions also help to enhance production recovery from viscous oil reservoirs. Moreover, ERD drilling has improved the feasibility of several remote prospects and minimized the slot availability constraint in the Jasmine field.
Hybrid Workflow Integration for Deep Reading Measurements and Geomechanics Process Enhanced Drilling Performance
Authors: Javay Alexandre , Imam Santoso Gagok , Syamsudhuha Aldia , Amer Ali Syed , Ahmed Sajjad
Published: November 2020

In a deep gas drilling project, landing the 7" liner at the top of a thin carbonate layer is critical to ensure ease of drilling and maximize reservoir exposure. Real-time multi-layer bed boundary detection technology was utilized to enhance top of reservoir detection certainty. This approach reduces the hard caprock interval in the next section which potentially causes wellbore instability and downhole tools failure, allowing drilling long reservoir section with minimum BHA runs.

Picking the top of caprock using conventional approach was challenging due to the lack of control points and the absence of distinct markers to distinguish the reservoir from the caprock. The variations in formation thickness and structural complexities also generated uncertainty in well correlations. Past experience was a series of downhole tool failures, resulting in multiple BHA runs to drill the reservoir section. Drilling caprock too deep could also accidentally expose the reservoir which would have catastrophic consequences such as total losses, well control situation, and sometimes missing the sweat zone completely.

The initiative comprised the introduction of a multi-layer detection resistivity mapping tool to detect bed boundaries with resistivity contrasts in the 8-3/8" hole section. The objective was to set the 7" liner as deep as possible to minimize the footage in the caprock in the next 5-7/8" section. Combined with in-depth well placement study to determine best trajectory for landing strategy, it enabled to push liner point closer to top of reservoir.

In subsequent implementations of this novel approach, the 8-3/8" section was deepened in average by 20 ft TVD into the caprock against the default 5 ft TVD previously followed. The drilling performance in the subsequent 5-7/8" section was significantly enhanced. Minimum shocks and vibrations were observed, and maximum drilling parameters could be applied at section start resulting in much higher penetration rates. The reservoir section was successfully drilled in two runs, doubling the average footage drilled as compared to previous similar runs. From a reservoir management viewpoint, the initiative contributed to increase the net-to-gross ratio across the pay-zone which improved the efficiency of the frac stages and eventually expanded the overall gas production.

This accomplishment was only made possible by the collaborative approach between the integrated services provider and the other stakeholders and was first deployed in a deep gas integrated drilling project. The client gave very positive feedback and the gas drilling unit is now considering implementing similar strategy in other rigs. From these promising results, it is believed that this initiative can also be implemented elsewhere in the Middle East where accurate well placement across thin carbonate layers is critical for successfully drilling the reservoir section.
Harnessing Benefits of Integrated Asset Modelling for Bottleneck Management of Large Offshore Facilities in the Matured Giant Oil Field
Authors: Nomura Yukito , Sai Shanker Ramadoss
Published: November 2020

An offshore giant oil field in Abu Dhabi is producing from multiple developed reservoirs with large offshore facilities including complex subsea pipeline network. However, due to increasing associated gas and water production trend, facility capacity can be insufficient in the future. Therefore, it is challenging to achieve planned oil production target. This paper demonstrates how to achieve it with cost effective mitigation method and IAM (Integrated Asset Modelling).

To achieve the objective, following organized methodology was applied. 1. Production network system modelling through history matching with the actual field observed data. 2. Integrating standalone reservoir models, production network and existing facility capacity constraint. 3. Simulating the model with specific field control method. 4. Analyzing the profile to identify the bottleneck for each period. 5. Preparing several debottlenecking options. 6. Assessment of the cost and impact on profile by debottlenecking options. 7. Proposing the most cost effective debottlenecking solution to achieve planned oil production target.

Several bottleneck issues of the existing facilities were identified through the modelling work; capacities of offshore complex separation, flaring, gas export, water processing, and gas dehydration. IAM shows those capacity constraints may cause oil production short-fall without proper management. In addition to that, friction in the subsea flowlines are also concerned because it increases back-pressure for production wells. Therefore, several mitigation options were evaluated and optimum solutions were prepared for each issue such as additional gas export line installation, converting existing subsea line to flowline, unhealthy well shut-in and additional well potential requirement, change of subsea network configuration. The study with IAM concludes all of those bottleneck issues can be mitigated by those debottlenecking options.

One of the IAM benefits is to enable us to evaluate production potential by bringing together existing information and models from all parts of the production system. It revealed various bottleneck issues within the existing giant offshore complex facilities. And it also showed how those issues can be managed by proper mitigation measures.
Diagnose of Corrosion Acceleration in Water Injection System Due to Influence of Dissolved Oxygen and Sulphate Reducing Bactria: A Case Study
Authors: Alwan Kareem A. , Al-Rubaye Wisam I.
Published: November 2020

Corrosion acts a major risk to water injection systems in oilfields. Dissolved Oxygen (DO) is one of the most significant causes of internal corrosion problems of carbon steel pipes worldwide. Consequently, the existing of both DO and Sulphate Reducing Bacteria (SRB) in injection water with reasonably high concentrations are greatly influencing on accelerating corrosion process in water injection system, that can severely impact costs of operations, and their control can introduce a vital challenge for the system operator.

An Iraq oilfield (Z), in which water injection for pressure support started in 2012 by five wells, then the wells number and the total injection rate are gradually increased in the following years by using both fresh rivers water and produced water. After 30 months, corrosion indications in water injection system are progressively increased. Many costly solutions are used to ensure continues water injection in this field.

In this paper, corrosion acceleration signs are observed during 5 years, to identify the corrosion status in different locations of water injection system. Corrosion indications are the leakage accidents in surface flow lines, workover operations to replace damaged tubing inside injectors, and increasing stimulation jobs as a result of the corrosion scaling accumulation inside injection wells and sand face. Many lab tests result of DO and SRB contents in water injected are collected, analyzed and in-depth studied to correlate the impact of different DO and SRB concentrations on the acceleration of corrosion problems in the water injection system.

The work results presented that the increasing of DO in water, leads to hugely acceleration of corrosion in all parts of injection system in the field under study. SRB as an anaerobic bacterium is playing a very complicated role in the corrosion of water injection system. SRB accelerates corrosion process by many ways, some of them are enhancing by DO concentration. The worst influence of SRB is expected to be grown with time when SRB go to the reservoir with injected water. SRB activity in reservoirs is reflecting by continuous upward of H2S concentration in reservoir fluids. This work introduced a reputable field experiences of diagnose corrosion process acceleration in a good case study in an Iraq oilfield, and how can reducing this corrosion speeding up by proper control of DO and SRB contents in water injected.
Introduction Of 66kV Infrastructure in UAE Offshore Oil & Gas Industry
Authors: Bin Ruken S.A.. A. , Kuwair M.B.. B. , Takieddine Oussama , R. Kamal Faris , Paul Raju , Mazumdar Sumit Kumar
Published: November 2020

This paper presents a case study by NPCC for the selection of offshore power distribution voltage in Al Yasat's, Belbazem Feed Project. The project involves large offshore power delivery to three ESP based WHT platform through subsea umbilical. This necessitates detailed study for the right selection of distribution voltage with an objective to minimize offshore cost.

The study involved survey of existing medium voltage transmission practice in most of the ADNOC offshore facilities and took into consideration of new technologies and development in offshore renewable energy sector with regard to 66kV infrastructure. The study considers 33kV and 66kV as the preferred candidates for comparison in offshore distribution voltage. Comparison is done based on subsea cable design, subsea power cable cross section, voltage drop, power loss, cable charging breaking current, GIS technology, CAPEX and OPEX.

For the delivery of large offshore power over long distance, the study resulted in the selection of 66kV distribution voltage. 66kV design reduces subsea cable cross section to significant extent while maintaining lower voltage drop and power loss as compared to 33kV design. Lower cable cross section results in reduction in cable weight, lower packing and transportation cost, less cable joints for long cables and increase in offshore installation efficiency. High voltage power transmission through long distance subsea cable involves substantial handling of cable charging current by breakers. The breaker tested as per IEC favors 66kV design since the breakers are tested at higher cable charging breaking limit (2.5 times) as compared to 33kV. This eliminates the requirement of shunt reactor in 66kV. New development in 66kV offshore renewable energy market such as introduction of wet type design in subsea cable, introduction of euromold cable connectors and compact GIS solutions makes 66kV design very cost competitive. The benefits which 66kV design offers lowers offshore CAPEX and OPEX.

The introduction of 66kV is novel to ADNOC and a major shift from existing practice in UAE oil & gas industry.
Successful Gas-Lift Start-Up Offshore Abu Dhabi, A Game Changer to Unlock Fields Potential and Increase Reservoir Recovery
Authors: Jaffres Benoit , Soomro Moazim , Zidan Maher , Mel Raphaele , Alblooshi Jamal
Published: November 2020

ADNOC Offshore started-up full field gas-lift activation for the first time in 2020. This major step will unlock field's potential by increasing reservoir withdrawal and increasing wells life by mitigating water production / breakthrough. This paper details the successful application of gas-lift from design during appraisal phase and early production stage to full field implementation. Fit for purpose design was implemented through multi-disciplinary studies and work. A strong change management in operating philosophy was requested to take onboard all stakeholders: Field development, Field Operation, Wells operation, Drilling and completion. Following appraisal and early production phases on a green field, wells design was optimized to ensure proper activation in most of the producers (two over three reservoirs developed). Due to full field development phasing, the first 30% of the wells completion were designed based on early production phase data. Before full field commissioning started, in well gas-lift valves were designed and installed, integrating all the dynamic information gathered during natural flow production. Valves change out was performed with the highest HSE standards, and taking into account full field development timing in order to reduce downtime and therefor maximize production. As gas-lift is new in the operating company, a strong change management was required: operating with gas-lift by field operation team, Completion design, Drilling and Gas-lift Production with SIMOPS. Gas Lift implementation will ensure the future oil production of the field as water injection and production will increase. Gas-lift practice implementation led to modifying the operating company's rules in multiple and deep aspects:

– Improve field team competencies in handling high pressure gas-lift system, – Increase completion and wells operation complexity, – Implement new SIMOPS rules.

As a first achievement, one well under reservoir integrity issue (low productivity due to reservoir collapse) was re-activated and production of existing wells was increased of several thousands baril. Further increase in production is expected in the following months as implementation is deployed to all required wells.
Downsized Multiskilling Program for Geoscience Students to Petro-Technical Professionals: How a Novel Integration-Based Cross Disciplinary Training for Interns Allows Reinforcing the Technical Competencies for Future Geoscience Workforce
Authors: Kelkouli Mohammed , Elghanduri Khaled
Published: November 2020

This paper describes a tailored multiskilling training program, newly designed for a group of students interns from different disciplines, that is based on the integration of different geoscience domains, leading to reinforce the technical competencies for future Petro-Technical workforce.

The program was inspired by an initiative launched for experienced geoscientists from different disciplines (Geophysics, Geology, Petrophysics, Petroleum ...), planning to move or recently joined a consultancy team, to help understand the full picture of consulting projects. This program was downsized and re-tailored for MSc geoscience students. While traditionally each intern works on a specific project or thematic of his domain with a mentor from his discipline (i.e. Geology student with a Geologist ...), the cross disciplinary program assumes a group of students from different domain working together as one team, for 3-6 months internship, on a single integration-based project (Field Development Plan "FDP" in our case), during that period they will be supervised by mentors for each domain.

Unlike conventional training program for students, as described in the previous section, the cross disciplinary approach allows each student to benefit from a theoretical courses-based learning in the form of class or web-based training for his domain, of course, as well as for other geoscience sub-disciplines, this is coupled with practical workshops and software learning/manipulation sessions. Hence, the intern will enrich his knowledge on other domains that were not necessarily covered during university courses. Looking outside of this mono-domain circle will help understanding what others are doing, how are they doing it, why are they doing it ... simply understand the way of thinking of each other across a consulting project team. The real benefit goes beyond that, in fact students from this program, when hired as Petro-Technical geoscientists, will easily integrate consultancy team of any size, know exactly what they have to do and why. The experience has demonstrated its effectiveness in preparing the future technical workforce.

The cross-disciplinary training program for a group of students from different domains working on a unique project, is a new concept that has never existed before. In addition, for the first time ever, university has granted these students (although from different departments) to present their MSc graduation projects together as a single project in front of a larger technical committee to cover all the disciplines.
Extreme-Performance Polymer-Locked Wireline Cable Conquers New Frontiers of Wireline Conveyance in Deep Extended-Reach Well in UAE
Authors: Varghese Mathew , Da Costa Junior Jose Augusto , Billingham Matthew , Varkey Joseph , Chang Sheng , Cevallos Antonio , Unal Burcu , Mangum Jared , Mansour Ramadan , Morrison Montie , Kim David , Sladecek Pat , Tran Tam , Wheatley Edward Jason , Correia Gladwin , Al Kiyoumi Ahmed Abdulaziz , Othman Alaa Abdelkarim , Almarzooqi Laila Sayed , Altamimi Ahmed Mohamed
Published: November 2020

An extreme-performance polymer-locked wireline cable overcomes the conveyance challenges in tortuous wellbores, enabling the acquisition of high-quality production logging data in extended-reach drilling (ERD) wells. The use of this technology enabled an operator in the UAE to successfully evaluate the downhole production and reservoir properties in four extended-reach wells drilled from an artificial island. Production logging data acquisition using conventional wireline cables is challenging in such wells because of extreme cable tensions.

This paper presents a case study about a novel approach of combining an extreme-performance polymer-locked cable and high force tractors to successfully convey production logging tools in an extended-reach well, where previous attempts with two conventional wireline cable types had failed. The new approach is based on analyzing the drag forces acting on the cable in the wellbore and modeling the tortuosity of the wells for determining optimal cable and tractor properties to minimize these effects. Based on this in-depth analysis, high-strength, torque-balanced, polymer-locked coaxial cable and high-force tractors with large wheels are selected for the job. With meticulous risk management and establishing a core team of key personnel, including field operations, the operator, and the product manufacturing center, this new technology is successfully deployed. Production logging tools are successfully conveyed to the maximum depth of 27,800 ft, and safely retrieved from the well. Excellent flowing and shut-in log data are recorded in a single descent, making it possible to accurately quantify zonal contributions from this horizontal lateral for the first time. Good tension profile with new cable shows the value of torque-balanced cables in high-tortuosity well profiles.

The success of the job created confidence in conducting safer, more efficient intervention in maximum reservoir contact development wells. It demonstrates the value gained by deploying advanced high-strength polymer-locked coaxial cables in combination with high-force tractors.
Asset Reliability in Practice: An Effective Combination of APM, AI and Simulation Solutions within a One Stop Environment
Authors: Eilers Joachim , Jacquin Steven , Burgos Basile Natalia
Published: November 2020

This paper describes a data-centric approach for increasing asset reliability and performance through the creation of single-source-of-truth environment (i.e., an Evergreen Digital Twin).

For many oil and gas facilities today, asset data is spread across a multitude of applications and databases, and most are not connected. This paper will show how data can be aggregated and contextualized, and combined with powerful simulation, analytics, and asset performance management (APM) tools to enhance performance, reliability, and maintenance.

For illustrative purposes, an oilfield use case will be presented involving the implementation of a an open and flexible operational intelligence platform (OIP) and an advanced simulation platform. In the proposed scenario, the OIP makes it possible to integrate and contextualize data from the simulator – making it accessible and useful for field operations personnel. The paper outlines the benefits and capabilities the combination of these tools can enable – including visualization and optimization of well production and the ability to simulate "what if" scenarios. It also discusses how artificial intelligence (AI) and/or APM tools could be integrated within the digital asset portal to provide early prediction of equipment failures and conduct failure mode analyses. The solution has been conceptually and technically proven; however, it has not yet been implemented by the field operator.

Overall, the use case highlights the value that can be realized by integrating data from disparate sources within a one-stop environment to make better operational decisions regarding complex oil and gas assets and facilities.
The Novel Approach to Pressure Transient Analysis in Highly Fractured Reservoirs: Case Study from Patardzeuli Field, Georgia
Authors: Ramatullayev Samat , Akbayev Beibit , Tsaplin Dmitri , Urazaliev Jenis , Goloborodko Andrey
Published: November 2020

Fractures are common features of many carbonate reservoirs. Given complex flow network that they create, characterization of dynamic behavior of these reservoirs is often complicated and becomes important, especially, if fractures provide primary pathways of fluid flow. In this paper a novel semianalytical simulator was used to understand the pressure behavior of naturally fractured reservoir containing a network of discrete and/or connected finite and infinite-conductivity fractures.

In this study an integrated interpretation methodology is applied to analyze well test data acquired in open hole section of exploration well drilled into highly fractured carbonate reservoir of Lower Eocene - Upper Cretaceous sediments on Patardzeuli field of Block XI-B, Republic of Georgia. The main steps consisted of explicitly modeling fractures - both wellbore-intersecting fractures and fractures located away from wellbore - using formation microimager data and calibrating the model to actual well test response using a unique novel mesh-free semi-analytical simulator designed for fractured reservoirs.

Study presents the results of well test of one zone performed in highly fractured carbonate reservoir drilled in Patardzeuli field. The pressure-transient response confirmed the complexity of reservoir and dominant contribution to flow regimes from fractures.

It is shown in this paper that there are many factors that dominate transient behavior of a well intersected by natural fractures, such as fracture conductivity, length, intensity and distribution, as well as whether fractures intersect the wellbore or not. Moreover, it was demonstrated that presence or absence of damage on wellbore-intersecting fractures in vicinity of wellbore will impact the pressure- transient behavior of reservoir and shape overall productivity of the well.

The novelty of the approach is the analysis of the dynamic behavior using a unique semi-analytical pressure transient simulator for fractured reservoirs. The simulator can be used to obtain a response for arbitrarily distributed infinite and/or finite conductivity natural fractures within the reservoir by modeling them explicitly. In this study, it allowed to maximize the value of well tests by assessing the effect of fractures on reservoir dynamic behavior and obtain matrix and fracture parameters where conventional well test interpretation tools would be deemed unviable.
Evaluating Percentage Cost Volume of Engineering, Procurement & Construction to Add Value in EPC Petrochemical Projects
Authors: Siddiqui Talha
Published: November 2020

This research analyzes a real-time data extracted from multiple Mega EPC projects (min 50 Million US Dollars) in petrochemical industry. The data pertains to the distribution of overall project cost in to three major segments in a typical petrochemical project which are engineering, procurement and construction. By knowing the percentage volume of cost in each of the three major segments in a petrochemical EPC lump sum project, improved efforts can be made to dedicate adequate resources & save significant cost in the relevant segment and in the overall EPC project.

Method used was that twelve (12) completed EPC lump sum petrochemical projects were selected for cost data analysis. Out of these twelve projects, cost for hundreds of line items segmented into engineering, procurement & construction was tabulated in the cost model spreadsheet. Against each line item, its corresponding cost estimated by Owner / End-user and all bidders (on average five bidders were taken) for each project was listed. Average cost of all 6 organizations (Owner and five bidders) was calculated and analyzed to a minute detail ignoring any outliers. The data was buildup from a single line item in a project to the complete level cost of engineering, procurement & construction for the particular EPC project.

Following criteria for the selection of data & projects was adopted for the purpose of this research: Petrochemical industry projects onlyProjects considered with individual overall cost of minimum 50 Million US Dollars (USD)Revamp and grass root projects

As the cost of engineering, procurement and construction was segmented for each project, it is concluded that average cost of engineering is approximately 9% of the overall EPC project cost (however engineering is driving procurement and construction which combine consumes approximately 91% of the overall project cost). Cost of procurement on average came out to be approximately 52% of overall EPC lump sum petrochemical project therefore it is most important that while preparing cost estimates of an EPC project, co-ordinated efforts by each of three disciplines that is engineering, procurement and construction are required to develop accurate cost estimates. As procurement corresponds to major percentage of an EPC lump sum project therefore investment in right resources in procurement & supply-chain can result in major cost savings for the organizations.
Cost Optimization in Onshore Pipeline Design and Construction
Authors: Al Braiki Ahmed , Kant Nath Nahum , Sulaiman Mohamed , Shivaji Gongade Ashish , Al Awadhi Ibrahim
Published: November 2020

"Optimization" or "Fit for Future" is the new norm for any industry in this competitive global environment. To encounter the challenges and to embed 100% HSE, efficiency, performance and profitability in operation, maintenance and new constructions, there is an urgent necessity to review and update existing design and construction specifications related to Pipeline. Hence, this paper summarizes the latest specification optimization efforts in pipelines material engineering without compromising the safety and integrity of the assets.

In ADNOC Gas Processing, specifications for various engineering disciplines namely, process, automation, control, electrical, static/ rotating equipment, piping/ pipeline, civil/ structural are followed in engineering, construction and maintenance activities. These were developed over years to steer the Company towards unparalleled reliability, operability and integrity. Now, the challenging market demands adaptability, agility and forward thinking with a need to "balance the performance with efficiency and profitability", without compromising HSE.

Hence, a "Lean" approach towards the specifications is emphasized by focusing on cost-saving and value addition in terms of optimized schedules and enhanced efficiency. A set of pipelines DGSs were reviewed internally based on International standards/specifications, best engineering practices, lessons learnt from involvement with Operation and Projects and consultants optimized specifications. Through this paper, major changes in pipeline specifications are elaborated highlighting potential areas of optimization and realized cost savings.

ADNOC Gas Processing (AGP) plays a strategic role in ADNOC and the UAE hydrocarbon value chain by contributing significantly for the development of the Emirates. ADNOC Gas Processing (AGP) operates and manages an integrated Pipeline Network of approximately 3500km length of Pipelines with the mission of uninterrupted supply to its Customers and any impact on the upstream plants. Various fluids are transported via pipelines such as Sales gas, Crude oil, NGL, Condensate, Water, Nitrogen and associated gases wherein majority of network contains Sales Gas. AGP is involved in executing many Major Pipeline Projects.

This paper presents "Fit for Future" initiative that has changed the organizational culture and reflects effectively in all activities across the Company. As all the technical activities are based on DGSs, update plan and potential cost realization are the main drivers for enhancing the performance without compromising HSE. This approach of re-visiting the technical specifications in the light of "high efficiency with low cost" can be adopted across other OPCOs and move towards common specifications for ADNOC.