bluuebunny/crossref_metadata_2025_split huggingface dataset:
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

Abstract
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

Abstract
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

Abstract
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

Abstract
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

Abstract
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

Abstract
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

AbstractSand 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.
How Do Bankruptcies in the Shale Sector Induce Operators to Focus on Value Creation?
Authors: Alsuwailem Majed Ayed , Selemankhel Malik 
Published: December 2021

Abstract
Between January 2015 and early 2021, about 76 of the approximately 2,160 small-to-medium independent companies in the tight oil sector filed for Chapter 11 protection. These filings mostly occurred in 2016 and 2019. These companies were negatively impacted by the low oil prices in these years owing to their lack of financial discipline and poor financial risk assessments. As a result, they declared bankruptcy.
News outlets tend to amplify bankruptcy filing announcements in the oil and gas sector. Nevertheless, our analysis shows that these bankruptcy declarations do not imply that the shale oil and gas sector collapsed. The ailing operators in 2019 were responsible for about 8.5% of total tight oil production in the United States. This volume did not disappear from the market because of the Chapter 11 provisions. Instead, the ailing operators either became more efficient and financially disciplined or transferred their assets to more efficient operators.
Over 33 independent companies have ultimately emerged from bankruptcy. These companies successfully reached debt restructuring resolutions with their investors, transferred equity ownership to investors or sold or leased their assets to other operators. Companies that failed to adapt exited the oil market through either liquidation or acquisitions by other companies.
Going forward, more consolidations are expected in the shale industry, especially among medium-to-large independent producers that accrued large debts in previous years. These producers will either enter bankruptcy owing to financial headwinds and market uncertainty or be acquired by larger companies. This analysis shows that bankruptcies in the tight oil sector may be viewed positively or negatively depending on the situation and perspective. Bankruptcies do incur different types of costs and losses to many parties. However, consolidation that improves the efficiency of resource allocation can be viewed as a positive sign for the economy. Operators, equity owners, debtors-in-possession and the oil and gas industry can therefore view bankruptcies within the industry differently.
Digitalization for Effective Performance Management Using Key Performance Indicators in Miscible Gas Injection Projects in South Oman
Authors: Kumar Kamlesh , Narwal Tushar , Alias Zaal , Agrawal Pankaj , Farsi Ali , Hinai Nasser , Abri Zahir , Quraini Aiman , Hadhrami Abdullah 
Published: December 2021

Abstract
South Oman has several pre-Cambrian reservoirs that are highly pressured (400-1000 bar), deep (3-5 km) and critically sour (H2S up to 10%). The combined STOIIP of these reservoirs makes it one of the largest gas EOR projects in the world. The objective here is to highlight the key performance indicators and digitalization techniques used for continuous and effective well, reservoir and facility management (WRFM) and production optimization, while honoring the facility constraints and gas export requirements.
Real time pressure data such as tubing head pressures, injection/production rates along with other data including maps, static pressures and production logs are used to define an appropriate set of performance metric at various levels, e.g. reservoir, sector or well. Digitalization of surveillance data helps in real time production optimization such as offtake management based on creaming curves according to gas sink availability and facility constraints. Key business performance indicators include gas utilization efficiency; MGI performance indicators include incremental oil, throughput, instantaneous and cumulative voidage replacement ratios, gas breakthrough level and time, ratio of reservoir pressure to the target minimum miscibility pressure; and facility constraints are optimized through gas balance, along with tracking field performance against the initial FDP forecasts.
Real time performance data is tracked using a commercial Real-Time Data Analysis tool (RTDA) and Database Analytics Visualization Tool (DAVT), with surveillance indicators targeted at well, reservoir and facility level. The above-defined Key Performance Indicators (KPI) are tracked against predictions from the field development plan in web-based portal developed at PDO (Nibras). Digitalization has enabled quick and effective monitoring of these KPI, short-term optimization of injection distribution and offtake rates to maximize oil production and overall value within facilities constraints and varying export gas commitments based on South Oman Gas Line (SOGL) network optimization. Using dimensionless plots and a standardized set of parameters help in developing a common understanding and benchmarking the MGI reservoir response with analogs and amongst different reservoirs.
This work presents a set of performance KPIs and short-term optimization methodology using digitalization and LEAN framework that are tracked in a web-based portal, RTDA and DAVT. It provides means to facilitate offtake decisions to meet variable export requirements while honoring facilities constraints, assess reservoir performance, providing valuable insights that helps in speedy reservoir management decisions. This process has been replicated across PDO for all related MGI projects and can benefit other development types, e.g. chemical/steam injection.
A Novel Workflow to Invert Broadband Seismic Data: A Case Study from Onshore Fields in Abu Dhabi
Authors: Afia M. , Mukherjee A. , Glushchenko A. , Elsayed R. , Paydayesh M. , Havelia K. , Ahmed J. , Vargas J. E. , Utami Y. P. , Elila A. , Al-Naqbi S. O. 
Published: December 2021

Abstract
Broadband seismic data has several benefits for quantitative seismic reservoir characterization. It is characterized by a significant increase of seismic frequency bandwidth on both the low and high sides of the frequency spectra. This work presents a novel seismic inversion approach to exploit the full value out of broadband seismic data.
The average wavelet from broadband seismic data is limited in high and low frequencies due to the short duration of the well log and the misalignment of the seismic data with the well-log synthetic at high frequencies. Limitation of the extracted wavelet and optimization can generate band-limited inversion results that do not capture the full range of frequencies. An alternate approach of dividing the data into three frequency bands resulted in extracted wavelets that capture the spectrum of each band, and in turn produced a reliable broadband inversion result honoring the full range of frequencies present in the data.
Inversion results gave a superior match of the estimated synthetic with the data spectra (Figure 1), and the reservoir was better calibrated at all the well locations. Successful recovery of the ultra-low frequencies enabled us to maximize the value of the broadband data. The workflow also pushed the frequency of the inverted properties to 80 Hz which helped in turn to characterize some of the relatively thinner layers, which were otherwise getting averaged out. Building a low frequency model for AVO seismic inversion using ultra-low frequency information leads to a significant improvement of predictability away from wells. As a prior model, a geologically constrained (4 Hz) low frequency filter was applied.
Review of the broadband AVO seismic inversion results clearly indicate a better match between the inverted traces and well log properties at the studied wells. Also, the blind well test results at four wells indicate an excellent match to the blind well logs, which adds a high degree of confidence on the inverted elastic properties. Also, the synthetic spectra of the ultra-low and ultra-high frequencies is captured and maintained in the inverted broadband seismic data.
The novelty of the new workflow is in the ability to effectively invert the broad frequency band of seismic data. Successful recovery of the ultra-low and ultra-high frequencies enabled us to maximize the value of the broadband data. Subsequently, the high frequency elastic properties helped in successful characterization of thinner reservoirs and will help in better optimization of the future field development initiatives.