bluuebunny/crossref_metadata_2025 huggingface dataset:
How a Single Field Development is Becoming a Hub
Authors: Felappi Francesca , Giovannini Simone , Giuliani Giovanni Matteo
Published: December 2021

The work presented in this paper shows how a single development evolved in a main Production Hub to unlock stranded resources, fast tracking subsequent marginal gas discoveries, by improving the flexibility of the subsea and treatment facilities. The approach was supported by a coherent activity about exploration program in the area, JV partnership and contracting strategy.

During the Execution phase of a subsea development, a new discovery was made in deep water, 35 km from the Floating Production Unit (FPU). Following this discovery, given the potential for further developments in the area (stranded gas reservoirs and further new gas discoveries), the decision of considering the FPU as a future Production Hub has been taken and FPU has been converted accordingly. The inlet facilities have been designed to guarantee the possibility of receiving well fluids at different pressure levels (high pressure for the new developments and low pressure for productions in depletion) with high production flexibility.

Several verifications have been performed to maximize the production flowrates at different pressure values, according to the envelope of data from exploration activities, via adequate arrangements for future expansion. These verifications considered the FPU as it is and with the implementation of minor and major modifications (including retrofitting offshore of new process modules). Design and timing of new equipment as minor/major brownfield modification have been set-up to cope with the modulate field profiles to keep FPU operating flowrate to its maximum value for longer time. In particular, the choice of new booster gas compressors has been planned, in order to select the best configuration for the most recent Hub development plan and to install them at the right time.

Converting a barycentric infrastructure in a Hub ensures a significant reduction of CAPEX for future developments (limited to subsea tie-backs only), allowing to reconsider projects previously evaluated economically unsustainable. Moreover, the Hub shall guarantee a long-term gas production by continuous addition of new discoveries in the area, making it an essential facility for the energy future of the Country.
The Benefits of Real Time Monitoring Application Artificial Lifting Parameter for Surveillance, Optimization, and Cost Reduction in Mature Field, Case Study Prabumulih Field
Authors: Fansuri Taufik , Miftah Akhmad , Parsaulian Sakti , Giyatno _ , Riviana Rina , Yanuardi Ayi , Mesia Putri Latissa , Taufik Suherman Andri
Published: December 2021

Prabumulih Field was located in South Sumatra, Indonesia. It has been developed as an oil field since 1920n (It was categorized as a mature field). At the end of 2019, the amount of oil well production was 149 wells (93% of the producing wells installed artificial lifting). As a consequence, to maintain production, artificial lifting surveillance activities must be a major concern and be managed properly. However, there are some challenges for surveillance, for instance, the location of well spread over a large area, the condition of the access road, and limited human resources.

Surveillance activity itself carried out manually required both much time and many human resources, however, acquired data was only once in a week for one well. That condition always emerged undesired occurrence because engineers who were in the headquarter did not obtain notification when producing wells were in trouble or suddenly off producing. In addition, there was a delay in time for evaluation and intervention, which resulted in decreased oil production. Nowadays, application, in order to accelerate the data retrieval process, was much needed, especially real-time acquisition and it could be monitored in several kinds of devices.

This paper will be presented about the benefit of real-time monitoring application in mature field, especially for artificial lifting well (ESP and Rod Pump). It has been installed since December 2019. There were several benefits obtained after installing this technology, those were related to surveillance and optimization. For instance, reducing time and human resources needed to obtained pump parameter data, engineers who are in the headquarter could observe everyday using both laptop/personal computer and smartphone, engineers obtained notification immediately when there were wells in a trouble, decision making for optimization and or intervention was faster, increase pump run life, and reducing well service program. Besides, there was another benefit that related to cost reduction, for instance saving rig costs for well service of 350,578 USD in a year because the amount of well service decreased from 49 times to 36 times, and obtained additional gross revenue of 547,945 USD for one year (cost for real-time monitoring for a year is 116,438 USD) because production deferment reduced from 19,577 STB to 5,105 STB. Based on those data, real-time monitoring could increase the economic condition of the mature field, so it was worth applying in a mature field.
Post-Investment Reviews of Oil and Gas Projects: Methodology, Lessons Learnt, and Limitations
Authors: Melet Arthur
Published: December 2021

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

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

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

Remote 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

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

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

The 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 benefits

Multiple 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 interfaces

It 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 2030

This 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.
Enhanced Thru-Tubing Ceramic Sand Screen: Performance Review from Pilot Installation in Offshore East Malaysia
Authors: Yeap Wei Jian , Hassan Nur Atiqah , Idris Khairul Nizam , Tang Ye Lin Catherine , Bakon Freddy Layang anak , Jamel Delwistiel , M Zin Zulkifli , Nik Khansani Nik Zarina Suryana , Madon Bahrom , Zimmermann-Ptacek Johanna , Gundemoni Bhargava Ram , Jackson Steven Richard , Barth Peter
Published: December 2021

Sand production remains as one of the most challenging complications in managing mature fields in Malaysia. More than half of the wells in Malaysian fields are completed with downhole primary sand control or require sand management throughout their lifetime. To further aggravate the issue, most primary sand controls installed have suffered from failure after an extended period of production. Thus, operators are often compelled to rely on thru-tubing metallic sand screens to reactivate idle sand wells. However, most metallic sand screens suffer from sustainability issue due to substantial erosion especially for those installed in wells with high gas flow rate. Therefore, alternative technology such as through-tubing ceramic sand screen (TTCSS) has been considered and applied due to its higher durability and resistance against erosion. This paper will discuss the evolution of TTCSS design and performance improvement in terms of longevity.

Field application in Malaysian mature fields has shown that ceramic sand screen demonstrates a longer lifetime when compared to conventional metallic sand screen. However, to further improve the mean time between failures (MTBF) of TTCSS, extensive studies have been conducted by carrying out detailed teardown investigation and computational fluid dynamic (CFD) simulation. Design changes have been proposed and incorporated to mitigate the erosion risk at end cap area based on previous well installation. The enhanced TTCSS were then installed in the same well with high erosional velocity as pilot testing. The operating well envelope and installation method were maintained following the previous installation. TTCSS with enhanced design were then retrieved after a period of three months for detailed evaluation.

Several criteria have been identified as key performance indicators for the success of enhanced TTCSS design. Throughout the pilot testing period, sand production at surface has been closely monitored to detect any sand grains larger than screen slot sizing. Upon retrieval, enhanced design of TTCSS shall not exhibit similar erosion patterns at end cap area which will affect the integrity of spring compensator system and cause the screen to lose its filtration mechanism. Lastly, enhanced TTCSS design shall prevent parting of screen during retrieval, reducing the risk of leaving the screen downhole as fish.

This paper will present the outcome of pilot testing of enhanced TTCSS by comparing the performance with the original design using both teardown investigation and velocity calculation. Suggestion for further optimization will also be discussed to ensure TTCSS remains as one of the competent candidates for remedial sand control which can offer greater durability and longevity.
Upscaling Float-over Installation
Authors: van Doorn Rory , Polkamp Sebastiaan
Published: December 2021

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

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

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.
Maximizing Condensate Recovery With Proven Cost Simulation for a Giant UAE Field: Base Study to Estimate Productivity between Horizontal and Vertical Wells
Authors: Sudarev Maxim , Al Hosani Mariam , Al Bairaq Ahmed Mohamed , Mohamed Ihab Nabil , Al Agbari Zainah Salem , Alyaaqoubi Nouf Sulaiman Hamad Salem , Latypov Eduard
Published: December 2021

Implementing the horizontalization scheme was developed for number of wells in order to increase the Gas and Condensate production, which will achieve sustainable and profitable Gas Supply.

It worth to highlight that most of these wells are being subjected to N2 and lean gas breakthroughs. By adopting a comparison methodology, the horizontal wells showed better performance in terms of HC production and CGR performance. The number of breakthrough in horizontal wells is less or delayed in term of time.

High production demand was promoting this project to take place, where the current situation was not supporting due to N2 and lean gas breakthrough, which is affecting the quality of the gas sales.

It was challenging to balance between high production demand, N2, and lean gas breakthrough. Initially, optimizing the production allowable was considered to maximize the production from high CGR wells and minimize the production from low CGR wells. The sidetrack scheme is important to penetrate the un-swept area and to maintain the geometry/distances between wells to prevent early breakthrough and minimize the interference. All results from surveillance and hydrodynamic simulation were integrated for final field assessment impact.

This work has resulted in positive expected outcome with few millions additional condensate recovery and extended gas production plateau. According the outcomes analysis the implementation plan was designed.
Seismic Reflections of Rock Properties in a Clastic Environment
Authors: Suleymanov Vagif , Almumtin Abdulhamid , Glatz Guenther , Dvorkin Jack
Published: December 2021

Generated by the propagation of sound waves, seismic reflections are essentially the reflections at the interface between various subsurface formations. Traditionally, these reflections are interpreted in a qualitative way by mapping subsurface geology without quantifying the rock properties inside the strata, namely the porosity, mineralogy, and pore fluid. This study aims to conduct the needed quantitative interpretation by the means of rock physics to establish the relation between rock elastic and petrophysical properties for reservoir characterization.

We conduct rock physics diagnostics to find a theoretical rock physics model relevant to the data by examining the wireline data from a clastic depositional environment associated with a tight gas sandstone in the Continental US. First, we conduct the rock physics diagnostics by using theoretical fluid substitution to establish the relevant rock physics models. Once these models are determined, we theoretically vary the thickness of the intervals, the pore fluid, as well as the porosity and mineralogy to generate geologically plausible pseudo-scenarios. Finally, Zoeppritz (1919) equations are exploited to obtain the expected amplitude versus offset (AVO) and the gradient versus intercept curves of these scenarios.

The relationship between elastic and petrophysical properties was established using forward seismic modeling. Several theoretical rock physics models, namely Raymer-Dvorkin, soft-sand, stiff-sand, and constant-cement models were applied to the wireline data under examination. The modeling assumes that only two minerals are present: quartz and clay. The appropriate rock physics model appears to be constant-cement model with a high coordination number. The result is a seismic reflection catalogue that can serve as a field guide for interpreting real seismic reflections, as well as to determine the seismic visibility of the variations in the reservoir geometry, the pore fluid, and the porosity.

The obtained reservoir properties may be extrapolated to prospects away from the well control to consider certain what-if scenarios like plausible lithology or fluid variations. This enables building of a catalogue of synthetic seismic reflections of rock properties to be used by the interpreter as a field guide relating seismic data to volumetric reservoir properties.
Remote Cementing Enabled with Automation Drives Reliability, Consistency and Efficiency; A Case History from Norwegian Continental Shelf
Authors: Bottiglieri Antonio , Dean Gregory D , Khatri Deepak K , Gianluca Ruggieri , Jaskiewicz Maja
Published: December 2021

Cementing is the fundamental first step and foundation for well construction. The traditional "let's go, mix it, pump it and bump it" cannot be the standard for the current and future offshore cementing operations.

As oil and gas operators continue to push the envelope for both innovation and efficiency in well construction operations, to drive energy transition, lower carbon footprint, service providers continue to look for ways to "do more, with less". The latest innovation is redefining offshore cementing operations with a powerful combination of field-proven expertise, equipment, processes, and software.

Remote Cementing Operations, the first of its kind in the industry, offers real- time and remote-operation capabilities, controls, and diagnostics of offshore cementing units. While conventional operations would typically involve a cement specialist working in an adjacent room on the rig, Remote Cementing Operations allows all cementing procedures to be controlled offsite by a cementing SME (Subject Matter Expert) from a Remote Operations Center (ROC), miles away from the offshore rig simplifying the operations, minimize errors and improve reliability. As the industry moves forward with a goal to lower carbon footprint, remote cementing enabled by automation will play a key role to implement innovative technologies that will help operators accomplish zonal isolation today and in the future while improving reliability, consistency and driving efficiency.

The new implemented process thus results in reduced costs, risks, and non-productive time (NPT) with fewer personnel on-board (POB)—all without sacrificing quality, safety, and performance.

A recent success case study is presented, where in an entire offshore well all the cementing operations have been mixed and pumped flawlessly from the ROC in one of the NCS (Norwegian Continental Shelf) rigs.

This work explores the relationship between the process of planning, execution and troubleshooting remotely when performing cement operations. By analyzing and reviewing different previous experiences on remote operations, the authors developed a more comprehensive decision support system for remote cementing operations.
Best Practice Methodology to Enhance Modeling Inflow Control Technologies in Dynamic Reservoir Simulators
Authors: Bertram Finlay , Moen Terje , Rinde Trygve , Jondahl Morten Hansen , Schüller Reidar Barfod
Published: December 2021

The methodology presented here will expand on current modeling of Autonomous Inflow Control Devices (AICD) to generalize for a wider range of fluid flow rates and phases. It will also address the challenges of modeling multiphase behavior of the reservoir fluid flow.

This paper presents proposed methods for selected devices, and device models supported by simulations. The proposed methods show the potential for qualified benchmarking of Inflow Control Technology (ICT) completed wells in dynamic reservoir simulations compared to the generic models currently in use.

New single-phase models for segregated and sequential flow are presented, and these have a potential for greatly simplifying mass flowrate predictions for multi-phase flow leading to more accurate analysis within dynamic reservoir simulators.
Update in Development and Deployment of Advanced Pulsed Plasma Drilling Technology
Authors: Gajdos Matus , Kocis Igor , Kristofic Tomas
Published: December 2021

Current drilling methods may only achieve relatively low penetration rates in hard formations found in deep wellbores. The relatively high wear rates of drill bits used in such applications can cause the overall economy of deep drilling to be non-feasible. Therefore, a step change is necessary for such formations. This paper presents update in development of the pulsed plasma drilling technology which allows controlled thermo-mechanical rock breakage efficient mainly for hard rock formations.

Pulsed plasma drilling technology does not melt rock but uses very short high energy pulses with high frequency which suddenly increase rock surface temperature and, thus, disintegrate its surface. Since the process is very swift, there is not enough time for creation of melt, which is viscous, difficult to remove and may act as a prevention for further penetration. Based on extensive experimental work done on 23 rock types we identified working windows for all of them. Based on this work, there is an "overlap window" where keeping the same parameters should enable drilling through any rock type.

The development team performed 1500+ various tests of pulsed plasma technology. During these tests we focused on qualitative parameters like efficiency of the process, sustainability of the process, etc. Quantitative parameters were not decisive when trying to make the process work in various operational cases. In total, we've run hundreds of testing hours of the technology. Now the team focus on quantitative parameters with the milestone of deepening the existing geothermal wellbores of other entities in 2023 to demonstrate the PLASMABIT technology at great depths. The system of this technology is composed of three main parts: PLASMABIT tool (Bottom Hole Assembly - BHA)Transfer line delivering fluid and power into PLASMABIT BHASurface equipment including rig, fluid and waste management, etc.

PLASMABIT BHA which is the major innovation is composed of the following modules which are under development within dedicated development programme: Pulse plasma drilling head disintegrating rockFluid and power distribution moduleControl and electronics moduleLogging moduleTwo tractoring modules securing movement and anchoringActive and passive cooling modules maintaining temperature of BHATransfer line connector

For the commercial application we intend to combine conventional drilling technology with plasma in the following way: Conventional technology would be used for initial hundreds/thousands of feet to overcome sedimentary/soft rock formations where it achieves competitive Rate of Penetration (ROP). Then, in deeper/hotter/harder formations we intend to apply plasma technology where it is much more efficient than conventional technology. Based on this, we intend to use hybrid rig combining rotary drilling and coiled tubing operations.
Produced Water Handling Using Downhole Oil Water Separation Study Case Onshore & Offshore Fields Abu Dhabi
Authors: Ladmia Abdelhak , Alblooshi Younes , Alobedli Abdullah , Zivanov Dragoljub , Kuliyev Myrat , Deblais Eric , Al Beshr Manal , Abdelkerim Ali Issa , Al Shmakhy Dr. Ahmed , Al Jaberi Bashaer , Abdullsalam Fouad , El Bekshy Amer , Almarzooqi Maitha , Maulana Sahid , Bin Ali Amirul , Douik Hela
Published: December 2021

The expected profiles of the water produced from the mature ADNOC fields in the coming years imply an important increase and the OPEX of the produced and injected water will increase considerably. This requires in-situ water separation and reinjection. The objective of in-situ fluid separation is to reduce the cost of handling produced water and to extend the well natural flow performance resulting in increased and accelerated production. The current practice of handling produced water is inexpensive in the short term, but it can affect the operating cost and the recovery in the long term as the expected water cut for the next 10-15 years is forecasted to incease significantly. A new water management tool called downhole separation technology was developed. It separates oil and & gas from associated water inside the wellbore to be reinjected back into the disposal wells. The Downhole Oil Water Separation (DHOWS) Technology is one of the key development strategies that can reduce considerable amounts of produced water, improve hydrocarbon recovery, and minimize field development cost by eliminating surface water treatment and handling costs. The main benefits of DHOWS include acceleration of oil offtake, reduction of production cost, lessening produced water volumes, and improved utilization of surface facilities. In effect, DHOWS technologies require specific design criteria to meet the objectives of the well. Therefore, multi--discipline input data are needed to install an effective DHOWS with a robust design that economically outperforms and boosts oil and/or gas productions. This paper describes the fundamental criteria and workflow for selecting the most suitable DHOWS design for new and sidetracked wells to deliver ADNOC production mandates in a cost-effective manner while meeting completion requirements and adhering to reservoir management guidelines.
Evaluation and Optimization of a Newly Developed Chemical for Sand Consolidation: HTHP Gas Wells
Authors: Al-Taq Ali , Alqam Mohammad , Alrustum Abdullah
Published: December 2021

Sand production is a common problem in wells completed in unconsolidated or poorly consolidated formation. Several problems are associated with sand production including erosion damage, and plugging of the well and surface production equipment, such as lines, valves, etc. Various mechanical solutions have been implemented to control or eliminate sand production. Screenless completion is an alternative method to conventional sand control techniques. Screenless completion methodology involves sand consolidation, a field-proven technique which offers viable and effective strategies to prevent sand production throughout the life of the well. Sand production can lead to production loss through sand filling up, production tubing restrictions, etc. Consequently, the need for an effective sand control is mandatory. Sand consolidation is a promising technique due to significant advancement in chemicals development for sand control. The challenge with the chemical consolidation systems is their ability to provide the highest possible compressive strength with minimum permeability reduction.

A newly developed sand consolidation system was assessed in this study for its effectiveness in both sand consolidation and retained permeability. Two techniques were investigated in preparation/conditioning of sand samples. Following the conditioning state, the sand samples were treated with equivalent amounts of the two components of the newly developed sand consolidation system (Resin-A and Resin-B). A consolidation chamber was used to cure sand under simulated downhole conditions of a temperature (300°F) and a stress of 3,000 psi. The consolidated sand sample prepared using 3 wt% KCl brine preflush was associated with a reduction in plug permeability of more than 99% with a compressive strength of 1,100 psi. In the second method, which employed a diesel preflush in the sand sample preparation step, an average permeability of 63 mD and unconfined compressive strength nearly 900 psi were obtained. The effect of temperature and flow rate on return permeability were investigate. The paper presents in detail the lab work conducted to evaluate/optimize a newly developed chemical system for sand consolidation in HT/HP gas wells.