bluuebunny/crossref_metadata_2025 huggingface dataset:
How Do Bankruptcies in the Shale Sector Induce Operators to Focus on Value Creation?
Authors: Alsuwailem Majed Ayed , Selemankhel Malik
Published: December 2021

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

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

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.
An Innovative IR 4.0 Solution Against Leaks Utilizing a Fully Integrated Pipelines Management System
Authors: Wathnani Abdulkarim , Hussain Badr
Published: December 2021

This paper demonstrates the Saudi Aramco Khurais Facility (KhPD) successful commissioning of the A Fully Integrated Pipelines Management System, in an effort to enhance its environmental emission performance. The project team conducted an assessment conceptually right from the beginning, to ensure that the value creations from this initiative can be realized, and the project remain cost effective and safely executed while meeting environmental objectives. Following successful deployment, the Khurais team carried out post installation performance assessment to ensure the outcomes and objectives from this project has been impacted positively. This paper covers the fully implemented solution to manage pipelines assets and enchantments followed by Saudi Aramco Khurais producing facility (KhCPF) Objectives: Share how a corrosion challenge of multi-phase flow within pipelines led to installation of a comprehensive solution to Pipeline Management Systems (common header connects all compressors) and how it was resolved through integration between two different systems. In addition, highlight how this approach enhanced the pipelines reliability, safety and most important the big environmental impact that helped Saudi Aramco to reduce its carbon footprint.
Understanding the Impact of Monsoon Season in Malaysia Water Based on Data Analytics for Planning and Executing Drilling Operation
Authors: A. Halim Rahimah , M. Yusof M. Hatta , M. Khalid M. Hanafi , Wong Hao Xiang , Abu Bakar M. Aizat , Sulaiman M. Zarkashi
Published: December 2021

Drilling operation in Malaysia are typically from offshore, thus offshore weather condition does contributed to the success or delay of a drilling operation. Wait on Weather (WOW) especially during monsoon season in Malaysia has impacted Operator's drilling operation, thus incurring additional cost to Operator. Monsoon season in Malaysia is typically from November to February every year. This paper will discuss and share the statistics of actual WOW happening from 2008 to 2019 in Malaysia water especially for jack-up rig (JUR) and tender assisted drilling rig (TADR) which are two common rigs in Malaysia water. The data was collected from one of the drilling operator in Malaysia. These data will be of assistance to Operator in better planning and executing drilling operation with the actual statistics as the risk factor. WOW is considered as non-productive time (NPT), thus NPT data gathering from Operators in Malaysia water were conducted. Data was then filtered to achieve the WOW data. WOW data was segregated between region in Malaysia which are Peninsular Malaysia (PM), Sabah (SB) and Sarawak (SK) as well as rig type, which are JUR and TADR. Distribution analysis were made to calculate the average and observe the maximum numbers of actual WOW occurrence. Further analysis was made to zoom into monsoon season in Malaysia which typically in November to February. 11 years data is generally good coverage for the analysis since it covers the up and down of oil and gas industry. Analysis was also done for both mob/demob and operation stage where it can be observed that WOW for mob/demob stage during monsoon season is significantly higher compared to operation stage. At the end of the analysis, the average or maximum numbers of WOW will be shared, and it will be used as recommendation for future projects to consider these figures as WOW risk factor and embed in the planning stage. This paper will help not only Operators in Malaysia water but the host authority on understanding the WOW risk factor during monsoon season. As WOW is not something that can be predicted, utilizing the standard results from actual statistic data for the past 11 years will assist engineers to incorporate the WOW risk factor during planning and execution stage. Rig and project sequencing can be optimized with understanding of WOW impact thus reducing the value leakage during operation due to WOW.
In-Line Inspection of Offshore Non-Piggable and Challenging 30" Subsea Flare Line
Authors: Al-Messabi Saqer Saleh , Zebidi Anouar Abdul Qader , Al Hosani Khaled Abdullah
Published: December 2021

The objective of the paper is to present the success story of carrying out an in-line inspection (ILI) on a 50 years old offshore subsea flare line. The project was particularly challenging because the 30" flare line had no pigging facilities, a reducer, a subsea tie-in connection, as well as other restrictions. The paper shall outline the approach and methodology adopted to conduct the inspection in a safe and successful manner while adhering to the company and government health, safety, and environmental regulations and meeting the shutdown window.

The 1 km long 30" flare line runs from a collector-separator platform to a flare tower. A site survey was conducted to identify process, space, and rigging related requirements. The shutdown window was allotted and fixed by the production teams. The line was first flushed to remove the hydrocarbons using a pumping spread mounted on a support vessel. This was followed by various modification works in addition to rigging up the temporary pigging traps. The works enlisted the help of support vessels and scaffolding teams. Extra controls were implemented due to the low maximum allowable operating pressure and the dirty pigging water in order to safeguard the property and environment. Eventually, 22 cleaning pigs were launched a in a train fashion. An Ultrasonic (UT) ILI tool was then used to gather information on the pipeline. Finally, the pipeline was dried using foam pigs.

The operation was a success mainly because of the planning factor. Many activities were integrated including the availability of a maintenance barge which played a huge role in the operation. This was the first pigging operation on the flare line which was commissioned in 1971 - a total of 185 kg of debris was collected. Moreover, the UT inspection provided quantitative data which enabled an accurate assessment of the subsea pipeline integrity status. It is estimated that USD 4 million were saved by completing the works mainly through efficient planning and utilization of in-house available resources. The inspection results will form a cornerstone in development of future asset replacement plans for this category of flare lines. The success has created potential savings for another 21 challenging flare lines planned to be inspected for the next 5 years.

The approach highlights the steps taken to conduct the quantitative ILI of an aged flare line (50 years old), with various inherent challenges, to explore the possibility of accurately inspecting and extending the remnant life of aged assets that are un-piggable, in a safe and environmentally friendly manner. Thus, resulting in positive impacts in savings and further optimizations in the asset replacement plans
Sustainable Production Enhancement of Valuable Products Via Operational Rectification
Authors: Agung Margono , Heryadi Wawan , Selladurai SanthoshKumar , Ventkataraman Ramesh , Al Qubati Ahmed , Yuniarto Dwiyono , Al Shamsi Abdullah
Published: December 2021

ADNOC LNG lies in the middle stream of the value chain, receiving and processing LP and HP gases from ADNOC Offshore. Supporting ADNOC Upstream's current oil production and future growth strategy while reducing its associated emissions of the process by delivering the associated gases to ADNOC LNG battery limit

ADNOC LNG processes associated and non-associated gases to produce LNG (Liquefied Natural Gas), Propane, Butane, Paraffinic Naphtha (P. Naphtha) and Sulfur. LNG constitutes Methane, Ethane and a little Propane and butane, with minimum constraints on GHV and density. In order to deal with market competitiveness in the context of a potentially prolonged low-price environment, ADNOC LNG has embarked on various initiatives to maximize its production by driving agility and efficiency throughout the value chain process. Delivering upon efficiency improvements, one of the contributing studies included optimizing the propane content i.e. reducing the C3 content, in LNG

Propane content in LNG has been varied, within operational limits, to maximize production of propane, which is more valuable/profitable when compared to LNG, whilst maintaining minimum LNG specification. In addition, slighting higher feed gas has been processed, to maintain LNG production rate. This has been achieved without hampering the plant stability.

The extensive review and analysis of the rectification units has been conducted as well as optimization in terms of temperature profiles and reflux flow rates was able to generate overall better product purification, thereby increasing production of desired and more valuable products.

This study has driven the investigation of additional benefits in production enhancement and quality improvements as the market value of Propane is relatively higher than that of LNG and thus yielding greater benefits. The overall performance trial basis deduced a total added benefit equivalent to 9 MMUSD/year YTD for train 3.
My Personal HSE Commitment Program – A Valuable Web Portal to Improve the HSE Leadership at a Workplace
Authors: Mohamed Mohamed Mokhtar
Published: December 2021

Safety at work is not just a priority, but a fundamental value, shared by employees, contractors and local stakeholders.

People are both as the starting point and the final goal of all its actions. This is why we work hard to ensure the safety of each of us and those around us, in order to eliminate all accidents. we are all committed to spreading and strengthening a culture of safety among all our people, employees or contractors, as an essential part of our work. Companies develop campaigns and projects to promote a safe and healthy behavior in any workplace and, more in general, in everyday life.

Virtuous tools and means of communication include workshops, theatre events and round table discussions, as well as video clips sharing what we learned from past safety hazards and the HSE Safety Golden Rules, our key safety rules. The continuous involvement of top management, contractors, representatives from local communities, or external guests, increases its commitment to safety.

This paper presenting one of the effective program which is designed and launched by an Oil & Gas Company so to allow all HSE leaders to self-evaluate their level of commitment towards HSE-related aspects and plan a number of important activities that would ultimately increase one's level of HSE commitment and enhance the safety culture through a Web Portal program called " My Personal HSE Commitment".

The portal provides the possibility to develop an action plan related to specific corrective and/or proactive actions/tasks that the user wishes to keep track of.

The most important part is also, The Web tool is furthermore capable of generating a personal HSE Commitment Poster that the user "The Safety Leader" can share worldwide thanks to the portal integration with Microsoft Outlook. Moreover, users can search others Posters – allowing for the widest dissemination of one's HSE Commitment among other users.

By applying this program, companies engaged all its Leaders and Management in the process of creating a strong HSE Culture and also, increasing the competition between leaders and program users by allowing each one to get access to others’ commitment posters.

By taking part of this program, each user can see - online - his direct HSE Commitment and be aware of others’ results which is creating a strong and transparent ability of positive competition and real outcomes based on each one's performed activities.

Once the companies applied this program, we can immediately see a considerable increase of HSE activities performed by all users and HSE leaders worldwide and this paper highlighted the results achieved & HSE performance improvement thanks to the way this program was created which helped a deep involvement of each leaders in the process of raising the HSE commitment of the company's management.
An Integrated and Digitalized Approach to Reduce the Well Failure Index During Covid-19 Global Pandemic in Shushufindi Field
Authors: Maulidani Oki , Escalona Pedro , Paredes Monica , Sierra Maria , Bonilla Christian , Villalobos Jorge , Bravo Luciano , Estevez Diego , Pineda Alexander , Chicango Edgar , Ramos Geovanny , Rodríguez Randall , Alabuela Luis , Freire Carola , Guaman Juan
Published: December 2021

The Covid-19 pandemic is an unprecedented condition to the global economy including the oil & gas industry. The ability to adapt to the imposed changes, requires creativity, innovation, digitalization of processes, and resilience. This work will show a novel integrated approach around four pillars which had improved operation efficiency and brought monetary value during a challenging 2020 in Shushufindi field, Ecuador.

The first pillar is new technology adoption. This aims to extend run life of critical equipment resulting in a higher well productive time. Examples of adopted technology: Chrome-enrich tubulars, downhole microcaps chemical deployment, de-sander and multiphase/extended gas handler. The second pillar is the P3 process (Pre-Pulling-Post) to quickly and effectively find the root cause of well failure that leads to definite remedial action. Digital enabler is the third pillar, its value come from reducing operational downtime and risk by using real-time surveillance capability, remote control, and data intelligence. The final pillar is to re-establish an effective communication with all stakeholders.

Various dashboards have been developed in order to provide the big picture of actual field condition in quickly manner as well as implementation of ESP real time surveillance & diagnostics, real time multiphase production test, and chemical treatment automation. Workshops, online technical, and service quality meetings are regularly conducted to ensure that recommendations and opportunities can be executed properly including contractual negotiations to enable new technology implementation.

Despite all the restrictions during covid-19 pandemic and some force majeures in 2020, this integrated and digitalized approach has resulted an outstanding outcome: Well failure index reduced from 0.62 in 2019 to 0.41 in 2020; Production deferment related to well failure declined significantly from 2,420 bopd in 2019 to 1,259 bopd in 2020, which translate in savings of $16.8 million dollars. In addition to that, there was a reduction on operational cost from $26.3 million dollars in 2019 to $15.2 million dollars in 2020.

This proven initiative has been supported and recognized by all stakeholders. Some new technologies and digitalization projects are in the process to be implemented in Shushufindi field as part of Ecuador digital strategy 2022. This successful integrated and digitalized approach can be adopted in other fields and will generate a huge business impact.
High Definition Acoustic and Temperature Logging for the Diagnosis of Complex Annuli Leaks and Communication
Authors: Obaid Hashem , Ashby Scott , El Sheshtawy Mohamed , Ikhsanov Niyaz
Published: December 2021

Maintaining annuli integrity is critical for safe and optimized well operations. Monitoring of tubing casing annulus (TCA) and casing-casing annulus (CCA) pressures is mandatory as it gives a direct indication of possible seal or tubular failures that may lead to a negative impact on HSE or well production. In cases where the observed annuli pressures suggest leaks and possible communication between tubing and TCA or TCA and CCA, a comprehensive plan should be put in place to detect and evaluate the possible leak sources and paths that will allow for proper remedial actions.

Logging techniques using spectral noise logging (SNL), and high precision temperature Logging (HPT) are one way to diagnose the source of a leak and communication path between 2 adjacent casings (for example TCA and CCA). The operation is performed by running the HPT and SNL log under shut in conditions to establish a base line, followed by logging under dynamic conditions. Dynamic conditions can include bleeding off the TCA pressure while all other annuli and tree valves are shut-in and injecting into the tubing-casing annulus while bleeding off the CCA.

The dynamic passes aim to activate the leak points. The SNL and HPT will capture the corresponding temperature and Spectral noise events revealed by the fluid flow though the leak points. These are compared to the base line shut in logs. The SNL is run in stations and can capture noise generated by fluid movement in a wide range of strength (decibels) and frequency within a wide scanning radius, while HPT can capture minor temperature changes of 0.02 Deg F.

The paper will discuss an example where the HPT and SNL were run along with a set of conventional sensors such as GR, CCL, and pressure in a HPHT gas well to diagnose leak points and a possible communication path between the TCA and CCA. The Logging operation was carried out rig-less with minimum intervention using wire line under the shut in and dynamic conditions. Spectral noise logging precisely captured the leak points and drew a clear picture of the casing integrity breaches in multiple points.

The results of the diagnostics and evaluation will now be used to design the appropriate remedial actions required to restore the well to the desired condition for production.
High Performance Tailored Mechanically Enhanced Cement Slurry Helped in Delivering Dependable Barriers Across HPHT Reservoir: Case Study from UAE Offshore
Authors: Manga Patrick , Mohamed Sherif , Bhaisora Devesh
Published: December 2021

The concept of zonal isolation has evolved recently addressing new industry challenges to provide dependable barriers throughout the life of the well. This helps ensure long term well integrity for safer and more efficient hydrocarbon production, especially for the fields predicted to have a long lifetime. This leads to tailoring of cement slurry designs for superior mechanical parameters to avoid deteriorating them under post cementing operational loads.

Following cementing best practices is a key parameter to achieve a successful cementing job, however adequate mechanical properties will help a cement slurry to withstand all the cyclic loads that the well will experience during its lifetime. Determining these properties and tailoring cement slurry designs to meet these properties will help ensure that the cement slurry will still survive these loads, all the way from placement until it has experienced all the post cementing operational loads including but not limited to multiple pressure testing, unloading the well, perforations, various thermal loads during well production, hydraulic fracturing etc.

The tailored cement slurry was able to provide an adequate solution of such challenges faced by an operator in Offshore UAE under a high pressure – high temperature (HPHT) environment. Stress modelling was performed for the life of the well considering post cementing operations. This helped in determining optimum mechanical properties required for the cement slurries considered. Specialized testing was performed in both lab and yard to achieve such properties for field execution. Based on various stress and hydraulic modelling, slurries ranging from 13 to 17.5 ppg were designed and pumped successfully in the wellbore.

Post cementing bond logs showed adequate placement of a tailored dependable barrier across a complete wellbore including an HPHT reservoir section. This approach can be used for wells with similar challenges around the world for long term zonal isolation.
Accelerating Digital Transformation in E&P Business
Authors: Karim Anak
Published: December 2021

What is Digital Transformation?

The intersection and confluence of four technologies – elastic cloud computing, big data, artificial intelligence (AI), and the internet of things (IoT) write (Siebel, 2019) is fundamentally changing how business and governments operate in the 21st century. It is somewhat of necessity as to how the industry and markets must behave today and some describe using digital technologies and advanced analytics for economic value, agility, and speed.

Industry analysts are in unison when they say that "investing in technology is not the same as digital transformation", it does not simply apply to changes in the company IT systems or simply the migration of company business processes, systems, and tools to funkier platforms with "cool" user interfaces. (Priyadarshy, February 2018) rightly said that while the E&P industry is more than 100 years old and has seen many ups and downs, the prolonged and cyclical impacts of decreased oil prices since 2014 warrants the need for transformational modification for the industry to remain operationally viable.

The Upstream sector did start the digital journey from many decades ago and with incremental improvements. Among the first steps being the creation of data via traditional supervisory controls and data acquisition systems (SCADA) and ingestion of operations report which were not fully digital such as daily operations, drilling and log reports. Over the years after that, as further back as two decades ago, the E&P industry claims to have adopted digitization and digitalization in the form of digital oilfields, however, this has failed to generate significant economic value (Priyadarshy, February 2018).
Cutting Re-injection CRI Uncertainty and Risk Assessment
Authors: Samy Ayman
Published: December 2021

It is the responsibility of oil and gas operators to recycle or dispose of drilling cuttings in a safe and environmentally friendly manner. Environmental regulations are very strict in establishing that green operations and cutting re-injection be as clean and friendly to environment as possible despite the associated challenges and cost. It is the preferred technique by the majority of international companies.

Cutting re-Injection operations include grinding down the drilling cutting to small particle sizes and mixing them with a water-based fluid (mud, water, gel) to form a slurry. The slurry is then pumped under high pressure into a disposal formation where fractures can be initiated and propagated. Existing wells can be used as appropriate by targeting watered-out formations far from hydrocarbon- bearing zones; sometimes operators drill new wells purely for cutting reinjection purposes.

The main sources of uncertainty include reservoir heterogeneity, permeability, pore throat size and fluid leakoff rates into the formation. The optimum scenario is to pump the cutting re-injection slurry into a very high permeability formation where screening out, plugging or well packing is unlikely, assuming solids are suspended and are completely lost into the formation. This scenario can only be feasible if the formation pore throat size is much larger than the solid size.

This paper presents how to conduct risk assessments for all possible scenarios considering all sources of uncertainties. The paper also shows that under some circumstances it is better to pump the cutting slurry into a very tight formation, such as shale (closed system), than a permeable formation with a high degree of uncertainty where screenout potential risk is most likely.
The Need for a Comprehensive Cement Database - A Novel Approach to Best Practices by Cataloging Cement Properties
Authors: Abraham Jocin James , Devers Cameron , Teodoriu Catalin , Amani Mahmood
Published: December 2021

In conventional well design, the cement sheath acts as one of the primary barriers of protection in the well integrity matrix. Once the wellbore cement is set, the well is exposed to various conditions and environments over time which can impact the integrity of the cement, the results of which are poorly studied and documented. Given that there are also multiple cement recipes and formulations – the task of studying downhole cement performance and categorizing said results becomes more complicated, requiring the need for an integrated database of information. The objective of this paper is to document desirable cement properties, develop an optimal method for presenting this data, and construct a database which integrates this information and allows streamlined data entry and retrieval.

Multiple variables must be considered when aggregating cement recipes and its corresponding properties over time. To test the behavior of these cement recipes over time, samples are created and aged in various controlled environments, and the properties tested periodically. The database was developed with a suitable interface to provide intuitive data entry and practical analysis capability, with proper inputs for the types of cement used, additives added, properties of the cement mixtures over time and any corresponding analysis performed on the samples in order to maximize best practice.

Differences in geology, drilling techniques and standards often require the use of different cement recipes with varied additives to cater to each job. These include accelerators, retarders, extenders, weighing agents, fluid and loss control additives, as well as special additives such as latex, fiber additives and foam cements. The database interface is designed to accommodate these variations in the cement recipes and track the properties of samples over time and give a comprehensive understanding of the behavior of the samples as they age. With information from the industry, literature, and laboratory experiments, properties such as the Unconfined Compressive Strength (UCS), thickening times, gel strength development, densities, to name few will be integrated in the data base. Data analytics strategies will also be applied on the information aggregated, and the properties of the samples over time will be correlated to field data as well as literature to ensure proper representation and accuracy of the data.

The database and the knowledge collected will be utilized as a source of information to enhance common cementing practices, as well as develop and refine industry best practices, which will be applicable to any cement job in the world. Currently, the database presented in this paper contains over 1000 unique cement samples, prepared and documented by multiple individuals with an aim to create a unique cement repository and database that focuses on long term cement properties.
Value of Cement Bond Logs for Evaluation and Improvement of Cementing Practices in Extended Reach Drilling ERD Wells
Authors: Alvarado Romulo Francisco Bermudez , Habib Abdelkerim Doutoum Mahamat , Duguid Jamie Scott , Srivastava Manish , Medina Ruben A. , Rocha Michelle , Vican Kresimir , Jambunathan Venkataraman
Published: December 2021

This paper discusses the value of cement logs as the core input to analyze the cement quality and validate the improvements made to cementing designs and practices of the intermediate casing string in Extended-Reach Drilling (ERD) wells. The ERD wells are being drilled from artificial islands in a field offshore in the UAE. The primary cementing objectives are isolating the reservoirs from their sublayers and protecting the casing against possible future corrosion across an upper formation. Cementing challenges include higher angle deviation, higher mud weight requirements resulting from an anisotropic, unstable shale formation present above the reservoir section.

Effective reservoir management requires sound zonal isolation to eliminate crossflow between different reservoir units. In combination with standard cement bond logs (CBL), ultrasonic technology has provided detailed information about cement quality and a qualitative indication of casing position in the borehole. These have also led to valuable insight into how continued cementing designs and practices improved zonal isolation.

Improvements in cement quality seen as a result of enhanced casing centralization, optimized hydraulic model, modified cement rheology, displacement rate impact, among others, were confirmed with the cement log evaluation program. The paper will present the ultrasonic and standard CBL responses, which support the enhancements made to the cementing design and practices that yield the desired results.

The cement quality has been improved in the ERD wells intermediate section through strategic modification in cementing practices. Cement evaluation logs have played a significant role in validating the cementing methods’ development. Consistently improved zonal isolation results have opened up the opportunity for future efficiency gains by eliminating routine CBL.
Data Driven Virtual Flow Metering: Leveraging AI and Edge Computing for Continuous Multiphase Flow Measurement
Authors: Schnabl Helmut , Wimmer Helmut , Nirtl Michael , Blazekovic Sasa
Published: December 2021

This paper describes the use of data-driven virtual flow metering (VFM) for continuous multiphase flow measurement, which has been developed and tested in an oil field well pilot in Austria. 12 ESP (Electric Submersible Pump) wells have been modelled and fine-tuned within the pilot. Hardware-based test separators were used to conduct quality control evaluations on the predicted production rates and calibrate the well models as required. For the practical deployment of VFM systems, we have addressed the need for optimized learning and scalability of the artificial intelligence (AI) models by means of what we call soft-sensing and will explain how to successfully deploy this technology on wells with artificial lift. Notably, the application of this software-based, soft-sensing VFM in combination with hardware-based multiphase flow measurement bears the potential to significantly reduce the CAPEX cost for future metering infrastructure investments and even reduce the OPEX of existing metering hardware by extending the duration of metering cycles. This makes data-driven VFM an economical option even for low-producing wells. Details of the well pilot project conducted with OMV in Austria will be provided. The use of soft-sensing VFMs via cloud computing for continuous multiphase flow measurement is a step toward the closed-loop, fully autonomous operation of oil fields.
Prediction of Threshold Sand Rates from Acoustic Monitors Using Artificial Intelligence
Authors: Vieira Ronald E. , Xu Bohan , Nadeem Asad , Nadeem Ahmed , Shirazi Siamack A.
Published: December 2021

Solids production from oil and gas wells can cause excessive damage resulting in safety hazards and expensive repairs. To prevent the problems associated with sand influx, ultrasonic devices can be used to provide a warning when sand is being produced in pipelines. One of the most used methods for sand detection is utilizing commercially available acoustic sand monitors that clamp to the outside of pipe wall and measures the acoustic energy generated by sand grain impacts on the inner side of a pipe wall. Although the transducer used by acoustic monitors is especially sensitive to acoustic emissions due to particle impact, it also reacts to flow induced noise as well (background noise). The acoustic monitor output does not exceed the background noise level until a sufficient sand rate is entrained in the flow that causes a signal output that is higher than the background noise level. This sand rate is referred to as the threshold sand rate or TSR. A significant amount of data has been compiled over the years for TSR at the Tulsa University Sand Management Projects (TUSMP) for various flow conditions with stainless steel pipe material. However, to use this data to develop a model for different flow patterns, fluid properties, pipe, and sand sizes is challenging. The purpose of this work is to develop an artificial intelligence (AI) methodology using machine learning (ML) models to determine TSR for a broad range of operating conditions.

More than 250 cases from previous literature as well as ongoing research have been used to train and test the ML models. The data utilized in this work has been generated mostly in a large-scale multiphase flow loop for sand sizes ranging from 25 to 300 μm varying sand concentrations and pipe diameters from 25.4 mm to 101.6 mm ID in vertical and horizontal directions downstream of elbows. The ML algorithms including elastic net, random forest, support vector machine and gradient boosting, are optimized using nested cross-validation and the model performance is evaluated by R-squared score.

The machine learning models were used to predict TSR for various velocity combinations under different flow patterns with sand. The sensitivity to changes of input parameters on predicted TSR was also investigated. The method for TSR prediction based on ML algorithms trained on lab data is also validated on actual field conditions available in the literature. The AI method results reveal a good training performance and prediction for a variety of flow conditions and pipe sizes not tested before.

This work provides a framework describing a novel methodology with an expanded database to utilize Artificial Intelligence to correlate the TSR with the most common production input parameters.
Maximizing Asset Value & Field Recovery with Advanced Completion Solutions – A Digital Twin Field Case Study with Multilateral, Intelligent Completion, and AICD Completion Technologies
Authors: Shahreyar Noman , Butler Ben , Corona Georgina
Published: December 2021

The drilling and completion of multilateral wells continues to expand and advance within the oil industry after three decades of accelerating adoption. The performance of these wells can be increased when integrated with advanced well completion techniques. The addition of intelligent completions (IC) and inflow control devices (ICD/AICD) enhances well performance and improves field recovery. This paper discusses a reservoir simulation case study that evaluates the productive impact these technologies provide when combined with multilateral technology (MLT), and the mechanism by which they achieve it.

A reservoir model is devised and simulates under dynamic reservoir conditions the field production of dual lateral and single bore horizontal wells. The simulation is conducted for three separate scenarios where AICD and IC are incrementally implemented. The results are compared across the scenarios and their value quantified.

The mechanisms by which estimated ultimate recovery (EUR) is increased will be discussed, including the increase of reservoir contact, drawdown distribution optimization, and the control and delay of water production.

The study will provide an overview on the theory behind the technologies. It will also review the workflow used to conduct the study, utilizing a combination of steady state nodal analysis software and dynamic reservoir simulation software. Additional information about the reservoir model, initial and boundary conditions are detailed, to provide insight into reservoir simulation methodology.
Contextual Failure Analysis Improves Reliability While Pushing the Envelope of Extended Reach Wells in a Giant Brown Field, UAE
Authors: Cantarelli Elena , Dang Khoa Le Pham , Escalera Hernan Melgares
Published: December 2021

The current combination of increasingly complex wellbores and tightening budgets forces operators to do more with less and find new ways to expand the drilling envelop. Often this pushes the parameters to the limit in order to achieve faster penetration rates. Operating at the limit or beyond impacts equipment reliability and project cost. A thorough failure analysis of the root cause(s) of every incident can help identify and address areas that need improvement. Identifying a cause fosters improvement while it simultaneously pushes the boundaries so the profitability of mature assets can be maximized.

Typical failure analysis attempts to determine the cause of a failure and establish corrective actions to prevent reoccurrence. In a large extended reach drilling project targeting a mature field, the approach to a single failure was expanded and projected in a proactive manner to anticipate the impact of current failure modes in future more challenging scenarios. This innovative method combines the classic failure analysis approach with a comparative approach designed to identify and classify each factor that contributed to the failure. This information is then compiled into a dynamic predictive risk matrix to improve the planning.

This method, thanks to the contextualization of individual failures and the multi-facet comparative analysis, revealed a pattern between reliability trends and environmental challenges. The pattern was correlated with the increased drilling difficulty over the lifetime of the project, and suggested that the long-established practices had to be revised to overcome the new scenario. The analysis contributed to the delineation of a strong action plan that immediately revealed a consistent service quality improvement quarter on quarter and nearly a 50% decrease in failure rate. The enhanced reliability had a direct impact on the performance that registered a significant reduction of the drilling time, thus lowering the overall well construction cost.

In today's economics where cost reduction, resource optimization and sustainability are at the top of the operator's priority list, failure analysis has become paramount to ensure continuous improvement. Effective analytic methods to identify and eliminate showstoppers are needed to minimize unplanned events and deliver within budget.

By digging deep into the root cause of incidents, this new approach to failure analysis enabled an enhanced, broader and more effective quality improvement plan that tackled service quality from multiple angles. From refining bottomhole assembly (BHA) design and risk matrix to drafting field guidelines and roadmaps, this approach also provided extra guidance and risk awareness for future well planning improvement. This particularly applies to mature fields where wellbore complexity increases at the same time budgets decrease and it's necessary to improve operational excellence to assure profitability.
Service Exchange or Major Overhaul. Which Philosophy to Implement for Gas Turbine
Authors: Youssef Karim Mamdouh
Published: December 2021

Maintenance costs and machine availability are two of the most important concerns to gas turbine equipment owner. Therefore, a well thought out maintenance program that reduces costs while increasing equipment availability should be instituted.

The correct implementation of planned maintenance relying on preventive maintenance optimization through perfect inspection frequency and scope provides direct benefits in the avoidance of forced outages, unscheduled repairs, and downtime.

Major overhaul is carried out for each gas turbine every 48,000 firing hours which costs around 1 M USD for each engine and with more than 8 months unavailability for the unit.

To increase equipment availability and enhance cost and time efficiency, alternatives approaches were evaluated including Service Exchange of gas turbines. It is found that service exchange is the best option for optimizing time and cost of overhaul of such engines.

This paper is written to improve Major Overhaul practice for existing Gas Turbines from ongoing practice of routine major overhaul including engine strip down, inspection and repair to Service Exchange of Gas Generator and Power Turbine every 48,000 firing hours.