bluuebunny/crossref_metadata_2025 huggingface dataset:
An Overview of Retrofitting Abandoned Petroleum Wells for Geothermal Energy Production
Authors: Ashena Rahman
Published: October 2022

Geothermal energy is considered a reliable, sustainable and abundant source of energy with minimized environmental impact. The extracted geothermal energy may be utilized for direct heating, or electricity generation. The main challenge to access this energy is tremendous capital expenditures required for drilling and completion. Therefore, this work discusses and evaluates retrofitting abandoned petroleum wells to geothermal as a commonly proposed solution to the mentioned challenge.

There are many oil and gas wells globally which are not used for production, injection or other purposes. Well abandonment is commonly considered as an essential measure to ensure safety and integrity of these wells, bearing huge costs and concerns for the petroleum industry. By converting abandoned or non-activated oil and gas wells to geothermal wells, it is claimed to be possible to produce geothermal energy and generate power. As a crucial stage for the claim verification and evaluation of feasibility or efficiency of this conversion, it is important to be aware of the practical and simulation case studies.

Therefore, in this work, this work presents a comprehensive overview and analysis of 20 case studies published from different countries, followed by important downhole and surface parameters. As for the downhole characteristics, production scenarios either open-loop or closed-loop, optimization of open-loop systems, borehole heat exchangers with their different types and dimensions, and insulations are covered. Next, surface cycles including organic Rankine cycle (ORCs), selection of circulation fluids, flow rates, and working fluids are covered, followed by produced and net powers with evaluation of coefficient of performance (COP) and thermal efficiency. This investigation shows there is good potential for producing geothermal energy from abandoned and non-activated petroleum wells.
Netzero Targets, Carbon Neutral Production… Yes You Can!
Authors: Eric Koenig
Published: October 2022

We claim decarbonization of Oil & Gas operations is feasible without major technology breakthrough. It first relies on energy efficiency and digitization, to help reduce the emissions amount and improve control. It can be completed by massive process electrification. The latter is initiated in some sectors, from pipeline compressors to FPSOs or LNG plants. It is being explored for process heating applications. We describe the approaches, hurdles, necessary development and changes in industry mindsets.

We have analyzed in depth more than thirty ‘low hanging’ decarbonization tracks. These start with the right GHG assessment and performance tool, based on the saying that you can't improve what you don't measure. These tracks are technically available and feasible today. They are compared in terms of feasibility in brownfield & greenfield, implementation costs, timeline & risks, as well as ROI and CO2_OI (Return On Investment and CO2 impact reduction On Investment).

We also identify several design paradigm shifts, applicable for all greenfield projects and provide some practical examples, from fully remote operations to flaring elimination. These design paradigm shifts are evaluated in terms of feasibility, ease of deployment and suggestions are made on how to integrate them in design and operations philosophy.

One major such shift is the need for Demand Side Flexibility when embarking on large heater electrification. We describe several approaches to address that.

We eventually analyze approaches such as CCUS, Green or Blue Hydrogen which are often the only ones considered for process decarbonization. We identify the pros and cons of these approaches and assess their real long-term financial sustainability.
Potential for Permanent CO2 Geological Storage, an Onshore Abu Dhabi Large Scale Assessment
Authors: Xu Siqing , Baslaib Mohamed , Keebali Aaesha , Para Humberto , BinAmro Ahmed
Published: October 2022

CCS technologies are well established, many ongoing projects have proven to be safe and reliable. Saline aquifers can be leading CO2 permanent storage candidates. A comprehensive multi-discipline study was carried out looking at the potential for CO2 sequestration in deep saline aquifer formations onshore Abu Dhabi. The area of interest is large in scale (regional scale) and consists of multi saline aquifer formations. The study has the added complexity that the same saline aquifer formations may be shared with near-by hydrocarbon exploration and production activities. The objectives were to analyze available geological data, define screening, selection and ranking criteria, identify key constraining factors especially concerning CO2 containment assurance, and arrive at regional storage capacity range estimates.

Considerable amount of geological data and studies are available, which can assist with regional Onshore Abu Dhabi saline aquifer formation geological characterization for CO2 storage assessment. The characterization synthesis forms the study basis. A benchmarking was conducted, published screening and selection processes were reviewed. By incorporating key formation geological characteristics, a list of potential formation candidates were generated.

A new set of guidelines for large scale (regional saline aquifer) CO2 storage candidate screening is proposed, based on the earlier guidelines set out in DOE/NETL-2017/1844 (2017). Detailed considerations and evaluation during the screening process are presented. A new candidate ranking and selection matrix is proposed. Highest ranked candidates from the ranking and selection exercise were identified. Dedicated regional scale 3D saline aquifer formations static model was constructed, and compositional simulation model developed for CO2 sequestration capturing the key CO2 sequestration processes/mechanisms. Storage capacity estimates were obtained from the dynamic model - the results published separately.

Large scale (regional saline aquifer) CO2 storage candidate screening, ranking and selection is a challenging process with many inherent uncertainties. It carries critical importance as the results and recommendations would pave the way for further feasibility or detailed studies and the definition of de- risking activities. It requires multi-discipline input and forms the corner stone for large CO2 storage project development. The study approach, new candidate screening guidelines, ranking and selection matrix may offer discernment for Operators planning similar assessments.
Accelerating the Path to Net Zero with Blue Hydrogen: A Route to Achieving Best-In-Class Environmental Performance and Economics
Authors: Hardy Robert , Vijh Neha
Published: October 2022

Most major economies around the world have committed to meeting ambitious net zero targets by 2050. As a versatile, clean and safe energy carrier, hydrogen is expected to play a crucial role in the transition to net zero. Large-scale, economic production of low carbon hydrogen is essential for the mass decarbonisation process, and this is especially true for hard-to-abate sectors such as the steel, cement and chemical industries, as well as dispatchable power, domestic heating and transport.

To accelerate the energy transition, Johnson Matthey (JM) has developed a unique carbon capture and storage (CCS)-enabled hydrogen production process that economically delivers very low carbon intensity hydrogen, commonly known as ‘blue’ hydrogen. The flowsheet combines a gas-heated reformer (GHR) and autothermal reformer (ATR), and provides a more energy efficient process than both conventional steam methane reforming (SMR) and flowsheets that deploy a stand-alone ATR, ultimately resulting in a higher hydrogen yield and reducing natural gas consumption.

JM's GHR-ATR blue hydrogen technology makes decarbonisation via CCS easier and cheaper than using an SMR. By delivering a CO2 capture rate of over 95%, the technology provides significant benefits compared with SMR and alternative ATR technologies.

Compared with conventional SMR, JM's GHR-ATR blue hydrogen technology demonstrates: Natural gas consumption – 10% lowerCO2 produced – 10% lessCapital cost for the CO2 capture system – 75% lower

Use of JM's unique GHR-ATR blue hydrogen technology will future-proof and de-risk projects by minimising the impact of rising feedstock, CO2 transmission and storage costs, as well as potential governmental schemes for carbon taxation. This process will enable hard-to-abate sectors to reduce Scope 1 and Scope 2 emissions by decarbonising their operations, accelerate the energy transition by producing clean hydrogen for consumers, ensure the viability of the plant for the future, and demonstrate commitment to sustainability.

JM's GHR-ATR blue hydrogen technology has been selected for deployment by HyNet North-West, the United Kingdom's first low carbon hydrogen plant. The 300 MW plant is expected to be built in the UK in 2026 (pending the final investment decision), and will provide hydrogen to industrial and eventually domestic customers.
Strategies for Reducing & Monetizing Fugitive Methane Emissions from Natural Gas Infrastructure
Authors: Diezinger Stefan , Chhibber Gautam , Siasios Georgios
Published: October 2022

Energy-intensive sectors like oil & gas and process industry are under intense pressure to reduce greenhouse gas (GHG) emissions, most notably methane, which has 28-34 times the global warming potential (GWP) of CO2. Though once generally accepted as a normal part of operation, fugitive methane emissions have come under significant scrutiny in recent years. Efforts to mitigate fugitive emissions are now a key requirement for future-oriented and optimized energy systems.

Today, there are a wide range of technologies that operators can leverage to address fugitive methane emissions from their activities. Generally, these can be broken down into four distinct categories: Solutions for continuous monitoring & detection – Covers technologies that can be employed to detect and measure fugitive emissions, including those that are unplanned (i.e., leaks).Solutions for emissions capture and reuse – Covers technologies that can be used to capture fugitive methane emissions that are a byproduct of normal operation (i.e., leakage across compressor seals). The methane can then potentially be monetized through reinjection into the process stream or utilized in onsite gas turbines or boilers for power and/or heat generation.Solutions for emissions reduction – Covers solutions for reducing leak rates of equipment, particularly across sealsSolutions for emissions prevention – Covers technologies that can be deployed proactively to prevent fugitive methane emissions releases that occur as a result of venting, blowdown, and maintenance.

This paper describes several solutions across these categories which are well-proven/established. The paper will also discuss recent global initiatives to curb fugitive methane emissions and how these initiatives may impact the regulatory framework as the Energy Transition progresses.
Large Scale PEMS for Tracking GHG and Criteria Pollutants
Authors: Nielsen Jan Sandvig , Weel Mogens , Falkenberg Magnus
Published: October 2022

This paper describes a system approach for monitoring greenhouse gasses (CO2, CH4, N2O) and air pollutants (NOx, CO, SO2 etc.) based on Predictive Emission Monitoring Systems. It describes the fundamental principle of PEMS technology including new work related to methane monitoring. Results are presented demonstrating the capabilities of the system to accurately monitor methane and other emissions from large number of emission sources.

There is a particular focus om methane (CH4) emission. Methane is a very powerful greenhouse gas that over a 20-year period is 80 times more potent at warming than CO2. Addressing monitoring and setting up reduction targets has become a top priority by major oil and gas companies. This paper describes an approach that can be used to address the needs from the oil and gas industry.

The studies conducted demonstrate that methane emissions vary significantly between emission sources and between operation conditions for a single combustion unit. This highlights the need for having an online system that measure the actual emissions based on actual operating conditions.
Experience In Onshore and Offshore CCS Development
Authors: Tucker Owain David , Seldon Lesley Rantel
Published: October 2022

Over the past fifteen years Shell have explored for, and developed, onshore storage at Quest in Alberta, Canada, and progressed offshore storage in a depleted field to final investment level. We are now developing new projects both onshore and offshore, in aquifers and depleted fields. This paper describes the projects and the integrated value chains – and highlight the differences between developing hydrocarbon resources where the subsurface is the upstream and the prime driver of value, and CO2 storage resources where the subsurface is effectively the downstream, and value is derived from the CO2 sources which are now the "upstream". The experience in developing regulations and projects in partnership with regulators is then outlined and linked to the subsurface technical work. We describe how the technical work builds upon and extends normal hydrocarbon workflows.

Key aspects of exploring for saline formation/aquifer storage and depleted field storage are discussed and some of the key challenges of managing the CO2 phase envelope in depleted fields are described. The balance of uncertainty between aquifer storage and depleted field storage is explained, with particular emphasis on the often-neglected challenge of inaccessible wellbores. We have successfully developed onshore storage that, by the time of the conference, will have injected over 7Mt of CO2 sourced from decarbonisation of hydrogen manufacture. In the UK we developed and submitted storage permit applications, and full FEED studies were executed, for depleted field storage. However, this project was halted when Government priorities changed. This has formed the groundwork for multiple new operated projects in North America and Europe. The startup and injection experience from onshore storage in Quest in Alberta, Canada will be presented.

Developing CCS projects relies on many of our petroleum engineering and geoscience domains of expertise and can, at first glance, look similar, but there are key differences, for example in containment, capacity, phase behaviour, sustained injectivity, and permitting. These novel aspects must not be neglected and require new analytical approaches. Many new entrants appear to be underestimating these challenges.
Disruptive Innovation in People Development
Authors: Khan Haroon
Published: October 2022

"People are our biggest assets" is a common statement by top leaders however in their entity balance sheet people are listed as expenses which can be reduced, replaced or even eliminated. In current processes, people could face disciplinary actions when their attendance shows they have less worked hours. The typical HR doesn't consider even if they work close to burnout daily. On the other hand low productive employee has no HR issues if they meet clock in and clock out requirements.

Effective processes are not used to identify learning needs and provide just in time effective learning solutions. People are sent to external (vendor) trainings and they return unchanged. The trust level in the organization is low. A visible generation gaps where the leadership is unable to capitalize on next generation for collective organizational success. In order to truly engage current work force, we need to re-think beyond current practices and bring new concepts to transform an organization as competent, dynamic & outcome focused.

One of the concept of this transformation journey is to replace organization structure from functional to project based. Departments and functions or divisions are to be converted to projects and each year projects are awarded as yearly goals based on company strategy. Employees are assigned to projects to complete them as one team. The progress and performance of employees is monitored through the appraisal system not only by the success of the assigned goals but the active participation and contribution of any employee in those project goals.

Job titles are eliminated and people work under project titles to enhance collaboration and flexibility. Job descriptions are replaced by competencies. Each project is created based on required resources, competencies and minimum required hours which are validated to ensure employees are fully occupied & engaged. Flexible working hours are introduced keeping required collaboration and project effectiveness. "Skill Trade" concept is introduced where employees will utilize 20 hours per month to learn competencies to enhance their projects.

By introducing skill trade, people will learn from each other (coaching & mentoring) in their areas of passion and to improve their projects. Boosting employee productivity by removing time bound barriers and it will enhance employee collaboration, engagement, commitment & competence.
A Life Cycle Carbon Footprint Calculator for Early Quantification of the Environmental Impact of Oil and Gas Services and Products
Authors: Montiel Edgar , Nachef Kinda , Marquina-Guinois Elodie , Spenley Karen , Van Kuijk Robert
Published: October 2022

Schlumberger has taken the lead in the oil and gas service industry by creating a footprint emissions quantification tool that balances the time investment with the accuracy required to assess the carbon footprint of technologies along their lifecycle, in order to draw comparisons and shed the light on less impactful services. As an initiative, this is intended to help with the pressing issue of greenhouse gas (GHG) emissions and how we may contribute to limit the impact of our industry on global warming.

Schlumberger's Technology Sustainability Team, with a representation from all divisions, has built a versatile lifecycle carbon emission calculator, integrating different oil and gas use-phase models. This calculator's development has entailed an in-depth understanding of the lifecycle assessment (LCA) framework as per ISO 14040, a detailed bibliography for the selection of the emission factors to be used, as well as a thorough technical understanding of the processes, equipment, and operations to develop the computation modules, and in particular the use phases models.

It is intended to be user-friendly and efficient, thus allowing even those who are not sustainability experts, to perform a carbon footprint lifecycle initial assessment of their product line or new services in their development phase.

We will present the methodology used, the learnings and the use-phase emissions computed in the context of Schlumberger services’ technology portfolio. A comparison of the carbon emissions on the full lifecycle of a product, computed with this tool versus a third party performed full LCA may also be presented to exemplify the investment return in both cases, and how such a calculator is used to assess a wide portfolio of products and services.

The presented tool allows to efficiently assess the "hot spots" on the lifecycle of a product. As the embedded carbon footprint estimate is one of the outcomes of the LCA, it can be put in perspective of the full lifecycle for further action taking. With the overall picture, the output of this tool can be the basis for discussion of opportunities with customers in their way to reduce their footprint.
Using a Digital Platform as a PMO in a Mega Project
Authors: Daniel K. Varghese
Published: October 2022

How project owners used a digital platform to ensure that their project reviews focussed on proactive actions towards the mitigation of potential issues rather than just discussions of project history.

A US$ 3,200 mega project to build a natural gas fertiliser complex at three different locations in 48 months was planned to be executed through multiple contracts by a SPV (Special Purpose Vehicle). The SPV was formed by 5 different public sector companies. This paper explores how they were able to utilise a digital platform to take over the PMO function successfully and with minimum human resources.

Since the project was of national importance and being monitored very closely by the Union Government, the project's management wanted the assurance of standardized reports to analyse schedule, cost, safety & quality, and to report accordingly to the appropriate levels. They engaged a cloud-based digital platform to ensure that, even with minimal resources (almost 1/10th of conventional manpower requirements) and even though it was a mega project with multiple stakeholders, the platform they chose ensured that all the typical PMO functions would be managed smoothly.
Unlock Hydrocarbon Potential of Najmah Kerogen Unconventional Reservoir (West Kuwait)
Authors: Nguyen Kim Long , Al-Morakhi Rasha , Verma Naveen Kumar , Quttainah Riyad , Sheikh Bilal Sajid , Youssef Ahmed
Published: October 2022

Hydrocarbon exploration and production in unconventional reservoir is under-developed in Middle East. Therefore, the understanding about this subject is still scanty which leads to conspicuous uncertainties in comprehensive reservoir evaluation and development. It plays a critical role to minimize the cost of exploration, drilling and operations. Detail plan for core acquisition and study is crucial to provide accurate and sufficient information to unlock the potential of Jurassic unconventional reservoirs in West Kuwait (WK). Hydraulic fracturing has proven to be a successful technique for increasing the productivity of unconventional reservoirs. However, before reaching that step, many factors should be intensively evaluated to minimize the risks. A potential area to place a MSF well should satisfy several criteria: high TOC, hydrocarbon maturity (oil, wet gas, or gas), less bitumen, proper containment to hold the vertical extension of fractures beyond the upper/lower boundary, etc…This paper aims to describe the integrated process of reservoir characterization to identify Najmah Kerogen sweet spots in order to facilitate the first Multistage Hydraulic Fracturing (MSF) well in West Kuwait (WK) unconventional reservoir.

The study showed that Najmah Kerogen reservoir in WK fields has world-class quality of hydrocarbon potential: average TOC is 10-13%, Kerogen type II/III, mostly in the oil window except some fields have high potential of wet gas/condensate. Thermal maturity increases basin-wards from South-East to North-West. The reservoir is organic-rich mudstone that comprises mainly calcite, dolomite, quartz, kaolinite, and pyrite. In general, the middle unit has lower organic content and higher brittleness compared to the upper and lower one. The reservoir characteristic of the middle unit is favorable for landing the MSF well. The upper unit contains high bitumen amount, so it should be voided in the plan of MSF. Fracture analysis shows the majority of natural fractures are following NNE-SSW direction that in line with regional tectonic understanding and results the favorable drilling direction in NW-SE to ensure the wellbore stability and maximize the efficiency of hydraulic fracturing job. As a result, Field-H was identified as the best candidate to drill the first MSF well in Najmah Kerogen (middle and lower unit) from the outcome of the study. The comprehensive understanding of Najmah Kerogen was crucial to develop unconventional reservoirs in WK fields, especially when the development of unconventional reservoirs is still in the early phase.
Successful Perforating Deployment in Deep Gas Wells Completed with Permanent Fiber Optic Behind-Casing for Hydraulic Fracturing. A State of the Art in Well Delivery.
Authors: Nunez Alvaro Javier , Al Husaini Nasser Khalfan , Al Kendi Al Muntaser Nasser , AL-Yahyaai Hamood Said , Al Hinai Adnan Saif , Abdelazim Mohamed Fathy
Published: October 2022

The scope of this paper is to discuss the methodology to perforate deep High pressure, High Temperature (HPHT) gas wells that are completed with permanent fiber optic behind-casing for hydraulic fracturing operations in Petroleum Development Oman (PDO), the main objective is to show the planning and successful execution of perforating and hydraulic fracturing operations in this new type of completions. The paper will show the enhancement of Well Delivery and the outstanding results in these challenging operations.

The paper will start by elaborating on this new type of completions with permanent fiber optic, the benefits, and the challenges associated to perforate the casing while maintaining the integrity and functionality of the fiber optic throughout all the hydraulic fracturing operations. Different orienting tools, gun sizes, shaped charges, explosive types, and gun phasing were evaluated and assessed to achieve the optimum system. Yard tests were done with an actual casing joint and fiber optic. Further, it will discuss the design, planning and successful job execution in one of the new gas wells with 4 fracturing stages completed.

Field operations were successfully executed in a deep gas well with 4 frac stages using plug and perf technique, the optimum and novel perforating system allowed to complete a total of 24 perforating runs without any damage to the permanent fiber optic behind-casing, it also allowed to successfully initiate and propagate the fracture in all stages. A final multi finger Caliper log also indicated that there was no tubing damage or deformation across the perforated clusters after milling all the frac isolation plugs. The well was successful delivered to production operations. The concept of perforating and fracturing deep gas wells completed with permanent fiber optic has been proved with substantial benefits, not only for the hydraulic fracturing operations but also for future Well Reservoir Management (WRM) and surveillance activities through the life cycle of the well.

Perforating and hydraulic fracturing in wells completed with permanent fiber optic is a novel approach to enhance hydraulic fracturing and well delivery, this is in alignment with the continuous improvement (CI) ideas and the lean thinking across the oil and gas industry. It's easy to replicate in other gas and oil fields, as well as horizontal wells to be hydraulically fractured, it will reduce cost, Health, Safety & Environment (HSE) exposure and will help increase the recovery of hydrocarbon reserves.
Case Study on the Application of In-Situ Combustion for Ultra-Low Permeability Oil Shale from Natih B Formation (Oman): Synthetic Oil Generation and Micro-Scale Pore Structure Changes
Authors: Varfolomeev Mikhail Alekseevich , Yuan Chengdong , Bolotov Alexander Vladimirovich , Saifullin Emil Rinatovich , Minkhanov Ilgiz Failevich , Mehrabi-Kalajahi Seyedsaeed , Derevyanko Vadim Konstantinovich , Al-Muntaser Ameen Ahmed , Suwaid Muneer Abdo , Sadikov Kamil , Taura Usman , Al-Wahaibi Yahya , Al-Bahry Saif , Joshi Sanket , Naabi Ahmed , Hasani Majid , Al Busaidi Rashid Said
Published: October 2022

Oil shale is considered as the world's second largest solid fossil fuel resource. Oil shale is an extremely ash-rich sedimentary rock loaded with organic matter. Most of the organic matter is rich in kerogen and a small amount of bitumen, which can be converted into synthetic oil using different thermal treatment methods. In-situ combustion (ISC) is a promising thermal enhanced oil recovery (EOR) method for the conversion of kerogen contained in oil shale to synthetic oil by oxidation. However, its field application is still limited due to difficulty in ignition, low combustion efficiency, and low rock permeability, etc. The main goal of this work was to determine the optimal conditions for synthetic oil generation and changes in the properties of oil shale.

In this work, a self-designed combustion tube was developed to evaluate the effect of catalyst and water, including improving combustion front propagation and shale oil recovery. Copper (II) stearate (0.1 wt% by metal) was used as an oil-soluble catalyst to improve the process of ISC. The performance of ISC was evaluated in terms of material balance, recovery factor, composition of evolved gases, and produced synthetic oil quality. In addition, the changes in the properties of oil shale rock were also investigated using 3D computed tomography.

According to the results of the combustion tube experiments, the presence of both water and catalysts is favorable for reactions that produce synthetic oil, sufficient heat generation (according to CO2 release) and hydrocarbon gases. The temperature profile and pressure profile indicate a successful ignition and successful establishment of combustion front for Natih B oil shale. The catalysts and water together improved the stability of combustion front and increase the efficiency of ISC process. The permeability was increased about 4 times higher after combustion.

Generally, these promising results technically prove the potential for the development of shale oil from Natih B Formation (Oman) by ISC process. The use of ISC can allow the conversion of oil shale into light synthetic oil with hydrocarbon gas production. Moreover, based on the obtained results the in-situ combustion can occur in ultra-low permeability reservoirs.
New Method of Offshore Platform Strengthening by Prefabricated X-Frames and Retractable Joints
Authors: Chatterjee Prabir Kumar , Shah Jinesh
Published: October 2022

This paper presents a new approach of offshore jacket strengthening with rigidly connected members and minimizing the number of clamps and bolts. Horizontal and diagonal braces between two successive elevations of a jacket in a plane may be combined to form a prefabricated X-brace which will be able to replace a set of existing damaged members. To facilitate easy installation, X-frame will be assembled along with its connecting half-clamps and one side of the X-frame will be provided with retractable ends. The annulus portion of the movable ends of the X-frame will be grouted to make rigidly joined new braces. The case study involves an aging offshore platform that undergoes a large amount of horizontal movement due to environmental loads. In spite of earlier upgrade with new piles and clamped braces, the substructure is found to be considerably flexible as a result of loose clamps and construction tolerance provided at the ends of each member. A detailed analytical study has been performed with the proposed strengthening scheme that shows significant improvement of the platform movement.
Remote Automated Well Test Operation on Un-Manned Well-Head Tower to Achieve Operational Safety and Efficiency
Authors: Joshi Mehul , Ramabhaskaran Padmanabhan , Shah Ankit , Soni Sandeep , Gupte Rohan , Mitra Jitendra
Published: October 2022

The unmanned operation in an offshore operating asset with large number of wells inherits a variety of operational and safety challenges, which demands innovation and emerging technology adoption. This paper demonstrates one of such operational activities related to well testing, where the value realized from mitigation of challenges brings significant process improvement in terms of safety and efficiency. Moreover, this paper also highlights the importance of planning and implementing such an initiative to overcome the process optimization challenges and associated change management risks.

The current process of well test operation requires the process engineer to divert the well strings by operating the valves manually to perform the test. The associated challenges related to the execution of such an operation were captured while devising the automated well test approach for remote WHT. This solution was formulated on a fallback strategy to retain the existing process in case of remote access failure. Using the SCADA system at the control location, the operator can execute the remote operation using a simplified process just by selecting a well and initiating the associated test operation.

This automated process enabled users to plan, execute, and control the well test operation seamlessly, realizing operational KPIs safely and efficiently. The manual interventions and related mistakes were minimized by using this automated approach. The interlock feature of the approach brought automation and operational efficiency to the process due to the system performing conditional checks on different associated equipment in this process. This significantly improved the manhour efforts and interlinked human errors, which could otherwise cause a significant loss of operational time and cost. The seamless integration with corporate data sources assured information flow from field to head offices fast and accurately, which adds to the process efficiency by avoiding human errors related to manual data handling. The integration aspect of this solution was unique as it was based on constant feedback and rigorous testing with end-users, along with robust architecture to incorporate various IT components and OT cybersecurity concerns.

The novelty of this solution was based on an approach that caters to the complexity, safety and process efficiency concerns of the current process when observed from the operational challenges associated with a giant producing field in a remote location. This brings the field in control and enables the asset operation team to plan the operations in a proactive manner, delivering quality outputs while achieving the critical operational KPIs.
Application of 4D Geomechanical Modelling for Fault Critical Re-Active Stress Evaluation in Underground Gas Storage
Authors: Chen Dong , Zhou Wei , Luo Ji , Huang Zhaoting , Xu Hanbing , Fu Ying , Cheng Ronghong , Lian Liming , Jin Quan , Qiao Xia , Wu Mimi , Yang Xiao , Huang Xingning
Published: October 2022

Fault stability is the risk of reactivation under dynamic stress conditions. The reactivation of faults in the oilfield is mainly caused by the increase of fluid pressure in the reservoir zone, with the quantitative evaluation index of the critical reservoir pressure required for fault reactivation under the current pore pressure condition. When the formation pore pressure reaches the critical stress, the corresponding fault part will be in a critical stress state. The slippage of the critical stress fault tends to cause fluids leakage. Therefore, the study of fault stability is of great significance to oilfield production; In order to guarantee national natural gas peak regulation and supply, the YH underground gas storage (UGS) has been proposed and is carried out with the project of expanding storage capacity and increasing production. The operator hopes to effectively guide the optimization of the limit operation pressure and ensure its long-term safe operation. It is urgently required to carry out fault stability evaluation for the YH underground gas storage. The operator plans to find out the conditions for the activation of the faults, with studies about the stability of the fault under the impact of mining and the impact of the system parameters on the stability of the fault. The results suggest that: whether the fault is in a stable or active state depends on the magnitude relationship between the apparent friction factor (k1) and the fault friction factor (k). When k1 < k, the fault will be in a self-locking state. However, when k1 ≥ k, the fault is in a reactive state. The apparent friction factor reflects the stress risk level of the fault under the collective impact of the in situ stress (including σ1 and σ3), the cohesion of the fault plane (c) and fluid pressure of fault (pi). Higher k1 indicates higher tendency of fault re-activation. k is a quantity factor determined by the friction angle (φ) within the fault. The larger friction angle of fault indicates higher friction factor and the more stable state. The system parameters (includingφ, c, pi, σ1 and σ3) will affect the stability of the fault after the change of initial stress conditions: the smaller cohesion of the fault plane and greater fracture fluid pressure indicate the fault will be easier to reactivate. This paper established the 4D dynamic geomechanical model of the YH underground gas storage and took the fault stability as the judgement basis to analyze the in-situ stress characteristics of different faults. The research results could be used to evaluate the UGS operation safety quantitatively under the impact of the dynamic stress conditions, which will provide technical guidance for optimizing the operation plan of the UGS.
Study, Analysis and Methodology Involved in Frac String Rotation to Minimize the Axial Efforts to Enhance Monobore Completion Integrity and Accessibility to Streamline Frac Operations in Unconventional Wells of Abu Dhabi, UAE
Authors: Ruiz Fernando , Al Hadidy Khaled , El Yossef Bassem , Amorocho Alexander , Nunez Ygnacio , Kumar Rakesh , Al Karra Mohamed , Lari Aliya , Fahmy Moataz , Ramadan Taha , Ibeziako Chuma , Hebish Ayman , Negoi Adrian , Cardozo Luis , Al Hendy Mohamed , Al-Rahma Rahma , Hamdy Ibrahim , Al Shamisi Eisa , Bin Sumaida Ali , Al Mutawa Ahmed , Coscia Marco
Published: October 2022

The purpose of this paper is to share the results and knowledge learned in implementing new procedure and techniques to rotate the 5-1/2", 26 PPF, T-95/P-110 Frac String (FS) during running into Unconventional wells. Developed by ADNOC Onshore ASR - UC Drilling Department at Abu Dhabi (U.A.E.) the novelty involves six (06) different technologies necessary to minimize axial buckling in the monobore completion while maximizing well accessibility and integrity during the Rigless frac operations.

The 6 key enablers technologies employed to rotate the Frac String up to 30,000 pound-ft: Connection: strength to withstand rotation required to release the axial buckling.High Speed Reamer Shoe: open hole debris cleaning / obstruction removal.Bonded Ceramic Centralizers: providing 80% standoff, reducing the friction factor and removing the mud cake with the rotation.Casing Running Tool: designed to wash down and rotate FS during running.Rotating Tubing Hanger: enabling FS rotation using different techniques and design a new mechanism for it after landed and locked into the Tubing Head Spool.Rotating Cement Head: ability to rotate the FS while pumping cement and plugs simultaneously.

Because of friction, sliding during running will result in helicoidal buckling of the FS that has a negative knock down effect on later completion operations / interventions and even in some cases not possible to reach the TD.

The results of previous UC wells where FS was run in sliding mode revealed issues due to the helicoidal buckling of the FS impairing annulus / cement bond quality, creating tortuosity and altering the Internal Diameter (ID) leading to issues in accessing the well bore with the Plug and Perf tool for the fracking operations.

The total depth for standard UC wells ranges from 16,000’ to 23,000’ MD with ± 12,500’ TVD and ± 8000’ MD 8"1/2 horizontal section dipping up to ±92° inclination for production reasons. Such profiles generate Friction Factor (FF) ± 0.5 in Open Hole. Based on performed simulations and depending on the well profile, surface torque required to rotate the string was between 25,000 to 30,000 pound-ft.

This paper will describe and provide details on how the FS helicoidal buckling was minimized and its limitations overcome thanks to the six key enablers technologies devised by Onshore ASR - UC Drilling Department. It will also highlight other important added benefits such as mud cake removal, improved annulus geometry and cement bond.
Implementing a Hybrid Digital Twin Approach in a Crude Unit Operation
Authors: Sama Rubio Sergio , Giménez Toni
Published: October 2022

Over the past decade, Machine Learning or, more generally, Artificial Intelligence, has made a stelar entry into the O&G world and is today routinely used from exploration all the way up to retail. At the same time, physics-based tools are still being seen as key for value generation and the O&G community is increasingly looking at combining "traditional" with "new" technologies in what has come to be known as "hybrid" tools. In this paper we explain how we Baker Hughes, C3 and KBC are combining Physics and Machine Learning to create Hybrid Digital Twins that help operators improve their margins, reduce their emissions and, in general, position themselves for sustainable growth.

Before they are in operation, plants (and oilfields alike) are typically simulated using physics-based tools. In practice, therefore, physics-based simulation models pre-date any plant data. Once plant data starts being produced, however, it becomes clear they do not match exactly the theoretical models that were used before operation. It also becomes clear that plants are operated in a very narrow range, due to quality, production and HSE requirements.

In this paper we document a hybrid approach for a digital twin used to generate optimized targets to a Crude Unit operation: synthetic data has been generated to overcome the limitations of available plant data. These synthetic data have then been used as additional training input for ML models, complementing instrumentation data, while at the same time, instrumentation data is used for calibration of the physics-based model.

This hybrid approach has been applied to a Crude Unit, in an optimization use case, with remarkable results. The final goal was to make energy optimization targets to operations through its machine learning algorithms which are based on two years of historical data optimized by a rigorous process simulator. The targets are manually downloaded to the unit multivariable controller by the operators. The hybrid approach has been found to combine the benefits of each type of technique: First Principles provides a sound bases for (limited) extrapolation, while Machine Learning ensures the First Principles models remain tuned to the reality of the process and complements the physics in areas where it is insufficient to model the reality (as is the case of equipment performance degradation/failure prediction). The range of what-if studies (and, correspondingly, optimization options) is thus radically extended.

This paper shows incremental benefits in optimization cases illustrated by a Crude Unit use case, resulting from the application of a hybrid digital twin using both physics-based and machine-learning models. The hybrid approach allows optimizers to evaluate scenarios beyond the historical operating envelope and opens the door to incorporating equipment condition considerations.
Takamul: A Digital Solution to Manage New Oil Performance from End-to-End
Authors: Al Shabibi Hilal , Ghulam Junaid , Al Azri Nasser , Mohammed Mushtaq , Sheheimi Awadh , Al Khabouri Khalid , Al Raisi Amina
Published: October 2022

In any E&P organization, drilling new wells is part of field development activity. This allows company to bring into production additional oil from different fields. Number of new wells drilled varies from company to company from a few to hundreds as in case of Petroleum Development Oman (PDO). Drilling new wells is a capital-intensive activity. Contribution to the overall production from new wells makes for higher returns on investment.

New oil production, is an integrated activity involving a number of departments and different stakeholders. Information and data come from different sources and has to be validated by different stakeholders.

Over the years, this has been done in a traditional manner with smart use of spreadsheets. However, with increase in activity, this way of working became cumbersum and time consuming. In business planning, it is important to select an optimum set of activities for drilling which will generate most new oil from allocated resources and budget. It should also be able to quantify opportunity oil in changing requirements. This means generating alternative sequences and comparing them against a set of KPIs and constraints. This exercise is required to be carried out within a cluster and across different clusters in a business unit. With the use of smart spreadsheets, this was getting difficult and time consuming. Resulting in suboptimal drilling sequence and missed opportunity to increase New Oil production.
Enabling Multiple Digitalization Opportunities Using Latest Wi-Fi 6
Authors: Langford William Louis , Al Kalbani Ayman Khalifa , Al Kaabi Ahmed Ali , Hassan Ahmad , Arce Rodel Francisco , Koodali Rajkumar , Chaudhary Kunal
Published: October 2022

The objective of the proposed paper aims to demonstrate an innovative approach and the value of retrofitting a plant area, where there is lack of adequate cellular coverage, with the latest Wi-Fi 6 wireless technology on an IT network. This helps to enable multiple use cases such as real-time headcount, asset tracking, and connected workers accessing key applications and video communication using tablets, mobile devices & digital wearables that requires high bandwidth and speeds, on an existing site and in a secure manner.
A Novel Approach to Building an Autonomous System that Enables Predictive Maintenance for Compression Systems
Authors: Cao Gaojing , Wang Xiangzeng , Kang Jinlong , Liang Quansheng , Xie Yundong , Williams Paul , Kartoatmodjo Gayatri , Henson Richard , Florez Fabian , Cui Jining , Fendt Andrew , Mu Xiaotao , Wang Lang , Yang Wan , Zhang Bo , He Jianping , Zheng Haibo
Published: October 2022

Big data and analytics are reshaping asset management workflows in the oil and gas industry, and the speed of implementation is accelerating. In many assets, the gas compression system is the core element to drive the process flow from one point to another and, is critical for maintaining the uptime of an asset. However, performance data often shows that compression systems have a high frequency of failures due to the complex assembly and high-speed moving parts. Therefore, the ability to monitor and predict the operational status of a compression system will benefit the asset in three ways: improve operational safety and reliability, increase the mean time between failure (MTBF), and reduce system downtime.

This paper presents a novel approach to building a predictive workflowto do just that, using a case study of a compression system deployed in a gas field surface facility to illustrate the development process and demonstrate the benefits. The workflow presented covers data collection and selection,cleaning, preprocessing, and prediction of compression system health status through machine learning (ML).