bluuebunny/crossref_metadata_2025_split huggingface dataset:
Post-Investment Reviews of Oil and Gas Projects: Methodology, Lessons Learnt, and Limitations
Authors: Melet Arthur 
Published: December 2021

Abstract

Objectives/scope
Discuss the analytical framework created by ADNOC for the implementation of post-investment reviews (PIR) of previous capital projects, and present an overview of both the results, the lessons learnt and the limitations of such exercises, based on ADNOC's return of experience on PIRs.
Without sharing confidential project information, the article will focus on providing actionable insights on ADNOC's chosen approach for PIRs, including best practices in terms of data and stakeholder management.

Methods, procedures, process
The overall approach can be summarized as follows:
Project choice: what are the tangible criteria to be used to focus PIRs on the capital projects with the highest potential in terms of learning opportunity? Data collection: what are the minimum data requirements to conduct a PIR for an O&G project? Variance analysis: what rules need to be followed to be able to generate two economics models (initial vs updated) that can be compared? Root cause analysis: how to organize the analysis process to explain the identified variances?

Results, observations, conclusions
PIRs can play an important role in the continuous improvement of O&G companies’ operations at the pre-investment stage, capital investment stage, and operation stage:
At the investment stage, a PIR can provide insights into the effectiveness of the decision-making and, specifically, help to identify improvement areas in the valuation (project economics), assumptions, risk management, and decision-making processes. At the execution stage, PIRs can be useful to quantify the impact of project delays and cost overruns on the overall project economics, and associate such variances with the relevant underlying causes. At the operation stage, PIRs be useful to quantify the impact of OPEX, production, and price variances (actual – forecast) on overall project economics, and associate such variances with the relevant underlying causes.

Limitations of PIRs
Uncertainty on what projects are likely to yield the best learning opportunities. Subjectivity: PIRs are partly subjective, as the results are largely dependent on data availability and methodological choices. Applicability of recommendations and acceptance from key stakeholders
Fiber Optic Deployed Behind Cemented Casing in a Vertical Deep Tight Gas Well Used to Enhance Hydraulic Fracturing, Monitoring and Diagnostics
Authors: Al-Jahdhami Ahmed Rashid , Chavez Juan Carlos , Al-Farsi Shaima Abdul Aziz 
Published: December 2021

Abstract
The use of fiber optic (FO) to obtain distributed sensing be it Distributed Temperature Sensing (DTS), Distributed Acoustic Sensing (DAS) or Distributed Strain Sensing (DSS) is a well & reservoir surveillance engineer's dream. The ability to obtain real-time live data has proven useful not only for production monitoring but during fracture stimulation as well. A trial the first of its kind in Petroleum Development Oman (PDO) used fiber optic cable cemented in place behind casing to monitor the fracture operations.
Several techniques are used to determine fracture behaviour and geometry e.g. data fracs, step down test and after closure analysis. All these use surface pressure readings that can be limited due to uncertainty in friction pressure losses and the natural complexity in the formation leading to very different interpretations. Post frac data analysis and diagnostics also involves importing the actual frac data into the original model used to design the frac in order to calibrate the strains (tectonics), width exponent (frac fluid efficiency) and the relative permeability. Monitoring the frac using DAS and DTS proved critical in understanding a key component in fracture geometry; frac height.
The traditional method to determine fracture height is to use radioactive tracers (RA). But these are expensive and the data only available after the job (after drilling the plugs and cleaning the wellbore). In contrast fiber optic can provide real time data throughout the frac stages including the proppant free PAD stage which tracers can't. The comparison of DTS and Radioactive Tracers showed very good agreement suggesting that DTS could replace RA diagnostic.
Hydraulic fracture stimulation operations in well-xx was the first one of its kind to be monitored with fiber optic. The integrated analysis of the available logs allowed us to benchmark various information and gain confidence in the conclusions. This helped fine tune the model for future wells for a more optimized zonal targeting and hydraulic fracture design.
In this paper we will share the detailed evaluation of the fracture propagation behaviour and how combining the fiber optic data with the surface pressure, pumping rates and tracer logs in conjunction with a fracture simulation platform where a detailed geomechanical and subsurface characterization data is incorporated to get a more accurate description of fracture geometry.
Multiphase Flow Boosting Without Using a Mechanical Multiphase Pump – Use of Innovative Surface Mounted Technology for Boosting Production from Inactive Multiphase Wells
Authors: AlShmakhy Ahmed , Shokry Ahmed Faoud , Beg Najam A , Peeran Syed M 
Published: December 2021

Abstract
Depleting reservoir pressures of mature fields or wells backing out due to high production line pressures can cause severe restriction in production from many oil wells, eventually leading to a complete cessation of production. These wells, however, still have considerable hydrocarbon reserves that can be recovered. Conventional methods to bring such marginal or inactive wells back into production involve power hungry multi-phase pumps or well intervention techniques such as N2 injection, workover, redrilling and artificial lift systems. Such methods are highly expensive and may require substantial infrastructure, especially on offshore satellite platforms which have limited facilities and space. Multi-Phase Surface Jet Pumps (MPSJPs), innovatively combined with novel compact separation, provide a surface mounted, compact, maintenance free and simpler method for boosting production from inactive multi-phase wells, without consuming any electrical power or fuel gas and avoiding any well intervention.
Multi-Phase Surface Jet Pumps (MPSJPs) are passive devices which use the energy of existing high pressure single/multi-phase fluids to reduce the Flowing Wellhead Pressure (FWHP) of low pressure multi-phase wells and boost their pressure to the downstream production header pressure. This patented system involves the use of a compact in-line separator upstream of the MPSJP to separate the gas & liquid phases and use the predominant liquid phase as the high-pressure motive fluid. MPSJPs can be used on their own or in combination with other boosting systems (e.g. ESPs, gas lift etc.). The applications also include revival of watered out, idle oil and gas wells.
Results from multiple worldwide applications have shown that MPSJPs can successfully boost production from low producers as well as revive dead wells that have not been flowing for a period of time. Wellhead pressures have been considerably reduced and production increases have ranged from 20% to 40% per well.
The advantages that MPSJPs offer over conventional technologies such as Multi-phase pumps, ESPs and well intervention techniques are several. MPSJPs are surface mounted (so well intervention is not required), comparatively low cost, have no moving parts, consume zero fuel gas/electrical power, have low footprint and use already available fluid energy. They are tolerant to variations in flow conditions, gas volume fractions (GVF) and associated slugging. They reduce the CO2 footprint by not consuming power and provide a radical, innovative, economical and environmentally friendly alternative to conventional methods. This paper discusses the use of MPSJPs and cites various case studies. The design and operational criteria are also highlighted.
Zero Condensate Flaring Utilizing Well Power and Equipment Modifications
Authors: Saad Gehad Mahmoud 
Published: December 2021

AbstractRemote gas wells unloading and remote field well testing becomes more challenging because of H.S.E. hazards and cost-saving. This process adds to environmental footprint concerns in the oil and gas industry. Also, government laws and restrictions become one of the main stoppers for this process that could deviate the project from safe operating status by introducing new risks and hazards.This paper introduces two cases related to oil and gas flaring. In the first case, the high-pressure gas wells uploading within the remote area requires high-pressure equipment and high-pressure pumps that suit condensate pumping; some availability issues hurdle this operation in many countries. Adding to that, the high-cost addition faces the planning operation when renting the special equipment needed. Alternative condensate flaring is considered nowadays forbidden in most countries' regulations and laws. Innovative practices and equipment modifications were built and applied to secure both environment and cost. In this method, the sound power is utilized after the unloading and testing to circulate the condensate from the tanks to the separator with a low-pressure pump then divert well flow to the division and the pipeline.The process reduces condensate pumping risk, and zero flaring were achieved. More than 3000 bbls of condensate were circulated monthly to the gas facility without affecting the operation procedures. The company applied this process to all testing equipment and considered it in the new contracts as a technical acceptance factor. Therefore, hazardous waste was reduced, emissions decreased, and safer operation is guaranteed for workers was observed.In the second case, the remote field requires a strong appraisal program, including long-term production and injection tests; meanwhile, interference between wells adds essential value before proceeding with the entire field development plan. This work presents a successful and valuable case supporting technical team decisions while considering H.S.E. as a priority.A field case study discussed in this paper presented the reduction of condensate trucking risk and achieved zero oil flaring. Sixty thousand bbls of light oil were injected safely within two months long term test to the same producer. An injectivity test for another reservoir was conducted without additional cost and without affecting the operation procedures.Besides the above-stated advantages of applying the new process in both cases, this process also can work in the high pressure and risky wills. Therefore, guaranteeing zero flaring and ensuring a lower carbon footprint while supporting the third corner of H.S.E., the environment while saving costs, can always be achieved.
An Innovative Approach for Simulating CO2 Injection in Reservoir Models
Authors: Scutiero Gianluca , Rossi Roberto , Luigi Daniele Facchi Guglielmo 
Published: December 2021

Abstract
Decarbonization is playing a major role in the near-future strategies of all the major oil and gas companies and one of most promising activity is the Carbon Capture and Storage (CCS). CCS consists in capturing CO2 coming from an industrial process and storing it in subsurface. In this project, three depleted reservoirs have been identified to inject CO2. Despite being located very close to each other, the three reservoirs are not in communication and the same surface facilities would be used for injection. The objective is to develop a suitable workflow for reservoir simulation to evaluate different injection scenarios. For this project, two wet gas reservoir and a light oil reservoir have been considered. A unique fluid description is not practical given the peculiarities of these reservoirs, as well as the construction of a single reservoir model. Currently there are some limitations in commercial solution to handle reservoirs coupling with different fluid description. A workflow has been developed using a controller that manages modules for simulating the whole asset. Injection rate of each well is calculated based on well condition and injection strategy. This process is performed for all the timestep of forecast. This solution guarantees to simulate the CO2 injection in three reservoirs in parallel in a reasonable simulation time (less than 2 hours), demonstrating the capability of overcoming the limitation of a commercial reservoir simulator related to the coupling of fields with different fluid properties. Different scenarios have been simulated considering alternative amount of CO2 to be injected. The gas injection scenario is fully accommodated inside the three reservoirs for all simulated scenarios. Moreover, the injection strategy is based on homogeneous re-pressurization of the three reservoirs and minimization of a possible well unbalancing. To achieve this objective, optimal weights to each field can be assigned to allocate the injection rates. The output of this simulation acts as primary input for dedicated studies (Cap Rock integrity, Thermally Induced Fracturing, Flow Assurance…) with the main advantage of being fully integrated at regional scale. The workflow applied in this project go beyond the main limitations of a standard reservoir coupling model. In particular, 3D reservoir models with different fluid description based on different equation of states, cannot be coupled using the standard workflows of the reservoir simulators, and anyway the available solutions are not fast and easy to implement. This approach provides a robust and flexible evaluation of the CO2 injection scenario in multiple reservoirs.
Demolition of Offshore Wellhead Topsides - Weight Engineering Challenges
Authors: Bodheswaran Sharath Chandran , Bharath Arjun , Varghese Cibu , Kamal Faris Ragheb 
Published: December 2021

Abstract
Some of the platforms installed in offshore fields in India have exceeded their design lifespan but continues to operate. For these platforms to continue operating safely and successfully, major revamp is required. As the wellheads are in operation beyond their intended lifespan and requires revamping due to their heavily corroded state, decommissioning, removal and replacement of existing offshore structures presents technical and economic challenges to Operating Company's and Contractors, alike. Due to the age of these platforms, availability of technical/engineering data is minimal and often needs to be developed from scratch.
The focus of this paper is on Weight Engineering and challenges in developing such data for a platform without as built information. The paper also touches on the different stages of executing the project including demolition engineering strategies applied, use of different installation aids to facilitate demolition etc during successful execution of Brownfield works in Mumbai High field by National Petroleum Construction Company (NPCC).
Optimizing Field Development in South Sultanate of Oman Through Deep Water Disposal Dwd Reclassification
Authors: Al Jumah Ali , Hindawi Abdulkareem , Shuaibi Fakhriya , Singh Jasbindra , Siyabi Mohamed , Al Salmi Marya , Hatmi Safia , Mazroui Anas , Harthy Khalfan , Azri Nasser , Sinani Yousuf , Mahrouqi Issa , Kindi Said , Saadi Faisal , Al-Joumaa Jihad 
Published: December 2021

AbstractThe South Oman clusters A and B have reclassified their Deep-Water Disposal wells (DWD) into water injection (WI) wells. This is a novel concept where the excess treated water will be used in the plantation of additional reed beds (Cluster A) and the farming of palm trees (Cluster B), as well as act as pressure support for nearby fields. This will help solve multiple issues at different levels namely helping the business achieve its objective of sustained oil production, helping local communities with employment and helping the organization care for the environment by reducing carbon footprints.This reclassification covers a huge water volume in Field-A and Field-B where 60,000 m3/day and 40,000 m3/day will be injected respectively in the aquifer. The remaining total excess volume of approx. 200,000m3/d will be used for reed beds and Million Date Palm trees Project.The approach followed for the reclassification and routing of water will: Safeguard the field value (oil reserves) by optimum water injectionMaintain the cap-rock integrity by reduced water injection into the aquifer.Reduce GHG intensity by ±50% as a result of (i) reduced power consumption to run the DWD pumps and (ii) the plantation of trees (reed beds and palm trees).Generate ICV (in-country value) opportunities in the area of operations for the local community to use the excess water at surface for various projects.Figure 1DWD Reclassification benefitsMultiple teams (subsurface. Surface, operations), interfaces and systems have been associated to reflect the re-classification project. This was done through collaboration of different teams and sections (i.e. EC, EDM, SAP, Nibras, OFM, etc). Water injection targets and several KPIs have been incorporated in various dashboards for monitoring and compliance purposes. Figure 2Teams Integration and interfacesIt offers not only a significant boost to the sustainability of the business, but also pursues PDO's Water Management Strategy to reduce Disposal to Zero by no later than the year 2030This paper will discuss how the project was managed, explain the evaluation done to understand the extent of the pressure support in nearby fields from DWD and the required disposal rate to maintain the desired pressures. Hence, reclassifying that part of deep-water disposal volume to water injection (WI) which requires a totally different water flood management system to be built around it.
Upscaling Float-over Installation
Authors: van Doorn Rory , Polkamp Sebastiaan 
Published: December 2021

Abstract
This paper presents the latest developments in Transport and Installation methods for Topsides up to 38,500mt.
For such heavy-weight structures Boskalis introduces a solution by combining the beneficial features of a Heavy Transport Vessel dry-transportation with the advantages of a DP2 Barge float-over installation.
This unique Transport and Installation approach, a so called "Piggyback T&I", may be characterized as follows:
Cost Optimization in Mega Oil & Gas Projects
Authors: Awwad Mohamed Ali , Al Radhi Ahmed Marei , Panigrahy Manoj Kumar , Gopal Suraj Kumar 
Published: December 2021

Abstract
Cost optimization is a continuous process in any business to drive cost reduction, while maximizing business value. Currently, cost reduction is being adopted by Oil & Gas firms as a core strategy, in order to maximize the profit margin. With global economies facing recession and wide fluctuations in energy demands, it seems low costs is becoming the safety valve for Oil & Gas companies. The oil and gas industry is under tremendous revenue and costs pressures. The indication is that globally, the oil and gas industry has experienced a huge drop in revenue in recent past. Some exploration and production oil firms have either halted or slowed down their production operations. Companies that manage their costs effectively will gain a competitive advantage. The oil market has less maneuverability with oil cartels determining the international price of oil. Project Costs are the major cost drivers of the Life Cycle costing & so Cost optimization of all mega Oil & Gas Projects became necessitated. Mega Oil & Gas projects, especially at ADNOC Offshore locations, are complex, labor-intensive and located inside Arabian Sea. These workforces are mainly from south Asian countries and so offshore sites are often subjected to the constraints of insufficient labor. These projects face multiple challenges in project management like severe weather, geographical conditions, insufficient work spaces etc. in addition to labor forces.
Cost reductions are accomplished through optimization of its strong and robust project management organization, management of uncertainties, high quality engineering, and implementation of value engineering during engineering, procurement, construction and commissioning (EPCC) phases and effective management of changes along with key Stakeholders expectations throughout the project life cycle.
This paper is based on the authors’ real life experience in implementation of many complex and mega upstream Oil & Gas projects with ADNOC Offshore who is currently leading multiple projects at DAS & Zirku islands. The most workable methods in this regard are listed here below.
Installation of Long Span Boat Landing on Float Over Platforms - A Case Study
Authors: George Charles John , Varghese Cibu , Kamal Faris Ragheb 
Published: December 2021

Abstract
Fixed offshore platforms are normally provided with landing platforms that enable berthing of supply vessels, crew boats etc. These landing platforms or ‘Boat landings’ are energy absorption structures provided on substructures (jackets) of offshore platforms. Their purpose is to facilitate personnel access from vessel to platforms for performing various tasks including manning the platform, its maintenance etc. Vessel also approach the platforms for providing supplies in case of a manned platform and for providing bunkers, spares etc. As such, boat landing is an integral part of offshore platform and its design and installation becomes equally important. They are preferably located at leeward direction as far as practical, to avoid accidental vessel drift into the platform.
For smaller standalone offshore platforms installed with Heavy Lift Crane Vessels, boat landing is installed after the jacket is piled to seabed. Since sequence of installation of boat landing is prior to that of Topside, such installations are straightforward and without obstructions from the Topside. For the bigger accommodation, production, process platforms located in super-complex (or standalone) with topsides installed by float over method, boat landings sometimes are in the wide float over barge slots. In such cases, installation of boat landing becomes very critical due to the post installation after the Topside and associated obstructions from the Topside. This is similar or more critical than a boat landing removal / refurbishment activity carried for a brownfield project.
This paper explores the challenges and associated steps adopted to execute the safe installation of these critical structures underneath a newly installed Topside. This case study details the installation of ∼300mt boat landings onto recently installed Greenfield platforms in Arabian Gulf using efficient rigging, suiting the EPC Contractors’ crane assets.