bluuebunny/crossref_metadata_2025 huggingface dataset:
Reducing Greenhouse Gas Emissions of Mobile Offshore Units; Pathway and Case Study Alternative Fuels for Self-Propelled Multipurpose Jack-Ups
Authors: Wassink A. , van den Berg E. , Fuster Piza P. , van Maurik P.
Published: November 2024

The worldwide energy transition and greenhouse gas emission-reduction targets impact the offshore industry. The sector, as part of the maritime industry, is working to meet increasingly strict international and regional emission regulations through measures such as energy efficiency and alternative fuels.

In this paper we describe the generic pathway to reduction of the operational emission of greenhouse gases for Mobile Offshore Units (MOUs). This is a relative new area of attention in the offshore sector. The paper provides an overview of monitoring and energy efficiency measures that are suitable for MOUs and their operations. In addition, it discusses applicable regulations and explores solutions for reducing greenhouse gas emissions and their impact on design of MOUs.

Specifically, we have performed a fuel emissions and vessel design impact case study for a self-propelled jack-up with 1,500 t variable deck load for two typical operating profiles: making an accommodation service trip or a field move in the Middle East region. We compared the global warming contribution of the greenhouse gas emissions of the operation and the impact of fuel storage for five different types of fossil and e-fuels. This high level assessment of the greenhouse gas emissions is based on their contribution to global warming over a 100-year period. This is done for the well-to-wake emissions of the assessed fuel types.

The case study assessment shows that fossil-based alternative fuels, such as gray methanol, gray ammonia or gray hydrogen are to be avoided as marine fuels: they create more greenhouse gas emissions than marine gas oil. It also shows that green (i.e. bio- and electro-) fuels can achieve a reduction of 79% or more in greenhouse gas emissions. The volume and weight impact of alternative fuels on the design of offshore installation vessels are included in the assessment. These findings can also be applied to other types of MOUs.

By replacing a fossil fuel such as marine gas oil with green alternatives, the IMO emission-reduction target for 2040 is attainable. The IMO net-zero ambition for 2050 will require further development of energy carriers and energy conversion systems with net-zero well-to-wake emissions. The green alternative fuels come with challenges regarding the weight and volume for fuel storage.

The energy transition timetable is driven by regulatory requirements and political choices, as well as by technological developments and the associated costs and rewards. The regional availability of alternative fuels and fuel supply infrastructure for the maritime and offshore sector also play an important role.
Vacuumized Pipe-in-Pipe Solution for Efficient Geothermal Heat Extraction Everywhere for District Cooling and Heating
Authors: Maver K. G. , Rasmussen J. P.
Published: November 2024

A new horizontal geothermal well solution is using a completely closed loop system for the circulation of a fluid in a vacuumized pipe-in-pipe (co-axial) system. The fluid is heated by the geological formation in the horizontal section of the well and returned to the surface with a very limited heat loss. With the closed loop solution there is no requirement for a geothermal reservoir with a certain porosity, permeability and flow characteristics and therefore the solution is independent of the geological setting and has a near universal application. This reduces most of the risks associated with conventional doublet hydrothermal well solutions, that often fails due to an impermeable heat reservoir.

For a successful execution, proven oilfield drilling technology and services are utilized. The drilled depth determines the temperature of the returning circulation fluid. The thermal conductivity of the geological formation of the horizontal well completion and the fluid flow rate controls the thermal energy output (MW).

The solution is suitable for initial subsurface temperatures around 150°C or lower. The formation temperature around the well will decrease over time due to the energy production. The temperature range makes the solution suitable for producing thermal energy for district cooling, directly for district heating and for various industrial usages.
Enhancing Operational Efficiency and Sustainability Through Al-Driven Fleet Management in the Caspian Sea, Cheleken Area
Authors: Espinoza R. , Butyrin A. , Vedat K. , Thatcher J. , Eldred M.
Published: November 2024

This paper explores the potential of Artificial Intelligence (AI) to enhance operational efficiency and sustainability in Dragon Oil's marine operations within the Cheleken Contract Area, Caspian Sea, Turkmenistan. Special attention is given to optimizing fleet capacity while addressing complex environmental and operational factors, such as variable channel depth, weather, operational priorities, and loading capacities. Through AI-driven optimization, the study identifies the optimal vessel plan to improve operational efficiency, reduce fuel consumption and costs, and lower CO2 emissions.
Smart Fracturing System for Screenless Sand Control Strategy in Cemented Monobore Completions
Authors: Surtman M. , Rozlan M. R. , Rasid M. F. , Bela S. M. , Zaman N. , Hussain M. , Makri M. H. , Amiruddin M. I. , Bohro M. N. , Deris M. N. M. , Thanaraju A.
Published: November 2024

Traditional fracpack designs generally involve setting up multi-zone downhole screen assemblies with isolation packers and pumping proppant slurry until screenout occurs. In contrast, the screenless fracpack using Smart Fracturing Systems avoids the need for costly wellbore cleanup operations, perforation, packer fluid, screens and packer assemblies, and proppant reversing procedures. Instead, communication with the reservoir is facilitated through frac sleeves and dissolvable darts for localized stimulation, which ensures uniform fracture propagation and sand placement in each stage. The reservoir is treated with Resin Coated Proppant (RCP) in a solid free carrier fluid, employing an underflush strategy to prevent nearwellbore collapse and proppant flowback during production. This innovative approach aims to reduce well construction costs while offering full-bore access throughout the entire wellbore. Production results demonstrated good productivity and effective sand control, with no proppant flowback at the surface.
The Future of Hydrates Management: NADAH – New Approach of Design Against Hydrates
Authors: Candelier C. , Lesage N. , Pierre T. Saint
Published: November 2024

Hydrates are formed of water and gas at high pressure and low temperature, conditions encountered in offshore environment. Lines plugging by hydrates is an undesirable outcome which must be avoided and has become a prevailing factor for the design and operation of subsea networks. Conventional design approach in deepwater developments consists in staying in the hydrates free domain whatever the scenario anticipated on the field. This approach often resulted in significant capital expenditure (CAPEX) with thermally insulated looped flowline, complex operating procedures having high impact on the operating efficiency and GHG emission.

This paper presents an innovative approach to manage hydrates risks in subsea developments, named NADAH (New Approach of Design Against Hydrates) and its implications for the future of offshore oil field development. NADAH is based on the understanding that some crudes have induction properties, which delay hydrate formation even when the pressure and temperature conditions reach the hydrate thermodynamic region. NADAH introduces a paradigm shift in hydrate management.

NADAH allows for mastered incursions of operating conditions into the hydrate thermodynamic region, but outside of the hydrate formation conditions, by taking into account the crude's induction capabilities at the early phase of the project. NADAH has been successfully applied on more than 5 projects, mainly in West of Africa, resulting in significant CAPEX and OPEX savings, as well as a reduction in production shortfalls and GHG emission.

For existing assets, NADAH allows simplifying the operations on site by extending the No Touch Time period and drastically delaying the requirement for any preservation operation, combining the natural capacities in delaying hydrates formation and the over-designed thermal specification. This optimization contributes to saving OPEX and production shortfalls reduction.
Data Driven Well Production Forecast for Improved Reservoir Management and FDP Optimization - A Case Study from a Super Giant Reservoir in Abu Dhabi
Authors: Belayouni N. , Gerges N. , Franco A. , Shaik I. , Ayoubi R. , ramatullayev S. , Gore S.
Published: November 2024

This paper aims to present an integrated approach for well forecasting that combines advanced Machine Learning (ML) techniques to provide accurate oil, gas and water predictions for existing and new wells in oil reservoirs.

Well forecasting is a critical task in the oil and gas industry for optimizing production and maximizing recovery from reservoirs. Traditionally, decline curve analysis has been widely used for well forecasting, but it has limitations in complex reservoirs or wells with uncertain decline trends. The proposed approach overcomes these limitations by utilizing advanced Machine Learning techniques that leverage complex real data for improved production forecasting. By incorporating ML algorithms, the proposed approach can provide more accurate and reliable predictions, particularly in challenging reservoir conditions where traditional methods may fall short.

The proposed approach for well forecasting involves several key steps. Firstly, historical data of wells, including production, choke, well head flowing pressure, producing days, injection data, well connection properties, and 3D properties, are collected and preprocessed. Next, 2D properties, such as well location, spatial coordinates, and spatial attributes, are extracted from the 3D properties of the reservoir using geospatial algorithms. Then, for existing wells an ensemble of ML supervised algorithm is trained well by well with enough historical data, and nearby wells are used to train non mature wells. For future new wells, historical data plus geological 2D properties is used to create a model per reservoir. This involves collecting and preprocessing data from nearby wells in the vicinity of the new drilling location to obtain relevant properties. Uncertainty intervals are calculated using quantiles to quantify the uncertainty in the predictions.

The integrated well forecasting approach presented in this paper provides a comprehensive solution for predicting well production in oil reservoirs. We used 2 different approaches to predict oil, gas and water production depending on the availability of historical data. Our approach allowed accurate predictions in complex reservoirs where wells have no clear decline trends. The use of uncertainty intervals provides a measure of prediction uncertainty, allowing for informed decision-making.
Stability Sensitivity Analysis of 100,000 Ton FPSO
Authors: Yu Boqian , Ling Aijun , Huo Guojing , Li Linbing , Li Hongtao , Liang Yuanhua
Published: November 2024

In this paper, a certain type of FPSO as an example, the relationship between the ship stability criteria and the change of the upper block in the preliminary design process of FPSO is proposed, and the basic method to ensure the stability of the FPSO is obtained. Based on the ship type and general layout of a FPSO, the problem of leaving enough ship stability criteria for the change of the upper block design scheme in the early design is studied. Through the calculation of stability and freeboard by MOSES, a large number of data are extracted and statistically analyzed by batch processing, and the amplitude of the change of FPSO caused by the change of the block is determined. Through the use of data processing and statistical methods, the limit of the stability change caused by the change of the block of FPSO is determined, providing quantitative ship stability criteria design method and stability sensitivity analysis method for the preliminary design of FPSO.
Breaking New Records of WRFM Gap to Potential in Artificially lifted Heavy Oil Reservoir in Petroleum Development Oman (PDO)
Authors: AL Riyami Samiya , AL Zahli Hamood , Hajri Hamood , Jabri Reham , Hinai Suliman
Published: November 2024

Well, Reservoir and Facility Management (WRFM) strategy provide a framework to manage and optimize wells, and reservoirs performance in any petroleum asset. WRFM aim to maximize hydrocarbon recovery, by ensuring the realization of the developed reserves, and optimizing short-term production level within provided budget. The scope of WRFM includes well integrity, surveillance, restoration, and optimization (CP-238 WRFM et al. 2022).

Gap to Potential (GtP) are one of the main WRFM excellence process that aim to reduce the gap between field production and potential. GtP exercise is meant to optimize the overall production system continuously (Al Balushi et al.2023). It has six main pillars which are deferment, water management, well optimization, fail Less, greenhouse gases (GHG) and energy saving. Execution of more optimizations are one of the main pillars that arrest field production decline, reduce frequent failure, and increase field production.

Field M is a matured heavy oil asset located in South Oman. In 2023 GtP optimization was one of the focus areas in field M well and reservoir management. The target was to boost all optimization activities with aspiration to uplift optimization contribution to total field production. This paper illustrates the work that has been implemented to advance optimization execution and demonstrate the resulted gain which raise field production dramatically and showing clear oil gain above the baseline. The execution of more optimizations includes proactive pump replacement, pump upsize, implementation of new technologies (Hydraulic frac, AICD, ESPCP and others), well clean-out and stimulation resulted in increase of optimization contribution to field M production from 4.75% in 2022 to 7.32 % by end of 2023. Field M GtP optimization activities breaking a new record in the GtP across PDO and generated around 3% increase in cash revenue.
Applying Machine Learning Methods to Identify Reservoir Features That Highly Affect Water Encroachment Based on Transforming Unsupervised to Supervised Model
Authors: Carlos Rodriguez , Ethar Al Naser , Mari Alqahtani , Osamah almansour
Published: November 2024

Machine learning methods are increasingly applied to identify reservoir features that significantly impact water encroachment in heterogeneous oil reservoirs. This study applies machine learning to identify reservoir characteristics most responsible for rapid water encroachment, leading to an increasing water cut trend. In heterogeneous and naturally fractured reservoir, multiple sets of features contribute to higher water cut trends, governed by the areal and depth variations in rock and fluid properties. The study leverages machine learning’s capabilities to quickly detect these trends and link them to highly influential features.

The approach begins with an unsupervised model that clusters wells based on their water cut trends, followed by supervised models that identify the reservoir features most significantly affecting these trends. Wells with similar water cut trends are grouped using time series clustering on oil producers, incorporating dynamic data such as oil, water, and total fluid rates; cumulative oil, water, and fluid production; water-oil ratio; water cut; bottom-hole pressure; and wellhead pressure. Additionally, data and information from water injection wells, including water injection rate and injection pressure, is used to enhance clustering based on areal patterns.

To integrate dynamic and static parameters and establish their connections, a supervised model uses the generated clusters as target and static parameters as inputs. Input data includes matrix and natural fracture properties such as porosity, permeability, rock types, picks and fluid properties, all of which exhibit variations. Data from these static models are prepared using harmonic, geometric, and arithmetic averaging methods to ensure proper input for the supervised model. Classification and Regression Tree (CART) models are employed to determine the relative importance of each variable, identifying those with the highest positive or negative impact on water encroachment. Based on these variables and their associated weights, water influx contour maps are generated for each cluster.

This novel approach not only identifies water encroachment trends in clustered areas but also pinpoints the static properties that most significantly impact these trends using supervised learning models. By utilizing CART, the relative importance of these properties per cluster is identified, allowing for the generation of a water encroachment map that reflect both water cut trend and the influence of key factors.

The generated maps offer deeper insights into water management and surveillance within each cluster area of the reservoir. This methodology provides reservoir engineers with a powerful tool to better predict and manage water encroachment in complex, heterogeneous oil reservoirs.
A Comprehensive Review of Machine Learning Application to Flash Calculations in Compositional Reservoir Simulators
Authors: Farmanov Ravan , Al-Shalabi Emad W. , Elkamel Ali , Markovic Strahinja , AlAmeri Waleed , Venkatraman Ashwin
Published: November 2024

Reservoir engineering often involves dealing with formations that contain several chemical species and show complex phase behaviors. One of the most critical aspects of this field is calculating phase equilibrium, which is usually achieved through numerical simulations of multi-component, multi-phase flow in porous media. These simulations are known as flash calculations and describe the phase behavior of specific fluid mixtures. Flash calculations are typically performed using reservoir simulators that are based on equations of state (EOS), such as the Peng–Robinson (PR) and the Soave–Redlich–Kwong (SRK). While EOS-based flash calculations are known for their accuracy in describing phase behavior within reservoirs, they can be computationally intensive and time-consuming.

Machine learning (ML), a branch of artificial intelligence, offers a promising alternative by predicting desired outputs through learning complex patterns among fluid properties of the reservoir. ML models have the potential to outperform traditional reservoir simulators in predicting phase equilibrium by significantly reducing the computational time required for flash calculations. This paper reviews various machine learning models developed over the years as alternatives to traditional flash calculations. It also explores the application of ML in both stability and phase split tests, discussing their limitations and providing recommendations for further improvements.
Enhancing Pipeline Integrity: Overcoming Challenges of External Corrosion Through Advanced Assessment and Repair Strategies
Authors: Kamonwan R. , Thanapat W. , Piyanut W. , Matina T. , Napatthamon V. , Chatchai L. , Jakraphan J. , Kriangsak P. , Khemmathas S.
Published: November 2024

This study investigates the integrity of a 16″ onshore pipeline in North-East Thailand, which unexpectedly exhibited significant external corrosion despite being equipped with dual protective systems—FBE coating and ICCP. Initial assumptions based on MFL pig inspections of two 10″ pipelines indicated a minimal corrosion threat, aligning with simulated inhibited corrosion rates. However, the 2021 MFL inspection of the 16″ pipeline revealed 2,265 external metal loss features at 1,266 locations, with corrosion depths reaching up to 30% of the nominal thickness, particularly around FJC.

Direct assessments confirmed the accuracy of MFL data, revealing that improper FJC application during installation and CP shield effects were significant factors in the corrosion observed. The investigation also highlighted the limitations of routine CIPS and DCVG surveys in detecting these issues. A new FJC repair system was qualified, and repair methodologies were refined, resulting in over 40% productivity improvement and zero incident cases from 2021 to 2024. This study underscores the importance of regular inspection, maintenance, and the development of robust repair strategies in managing the integrity of aging pipelines. The findings contribute to the field of pipeline corrosion management and offer practical solutions for similar challenges.
Maximizing Value Through Novel Approach to Project Implementation - Alternate Methods to Avoid Shutdown
Authors: Kanna Vinoth , Karam Saif Abdulla , Mukherjee Rahul , Ganesan Suresh , Anwar Syed
Published: November 2024

Upgradation of the old glycol flash gas flare was a challenging project considering many factors, namely, shutdown requirements, timeline of implementation, HSE concerns in the existing flare system, pre-construction activities, brownfield interconnections, and fit for purpose design. The project was a key HSE improvement project to ensure that the glycol flash gas flare systems operate with all the necessary HSE design elements.

A unique approach was adopted while implementing this project to avoid shutdown and execute the entire project using the mobilization of a mobile flare to keep the plant in operation while the construction activities were in progress. Since this was a new approach extensive meetings and coordination were required to safely execute the project.

This paper defines the overall design basis, the project execution methodology, process description of the natural gas liquids dehydration process, typical list of deliverables generated during the project and value maximization through novel approach for the activities related to Glycol Flare Upgrade. The objective of this project was to upgrade the existing glycol flare and demolish the existing glycol vent stack. The project scope included the installation of new flare components, such as velocity seal, windshield, pilots, thermocouples, HEI ignitors and flame front generators, as well as a new ignition skid with local control panel, conduits and cables. The project also involved the modification of the existing piping, instrumentation and control systems to comply with the latest company standard for flare systems.
The Longest Super Slim 3-7/8in High Angle Slant Profile Drilled Successfully into the Least Stress Direction – Kuwait Case Study
Authors: Al-Ajmi H. , Al-Saadi D. , Shadad N. , Al-Raish A. , Al-Mutairi F. , Nouh W. , Farhi N.
Published: November 2024

The objective is to drill a long super slim 3-7/8in high angle 76º inclination profile to maximize the primary reservoir exposure cutting through a depleted zones in a harsh drilling condition and pressure regimes into the least stress direction.

The actual drilled profile was checked first from surface down to the last 5.0in liner shoe depth at 18,044’ MD to measure the wellbore tortuosity and predict the cased hole friction factor the buckling areas to assure an optimal weight on bit delivery expected while drilling.

A full analysis for the open hole was taken using a nearby wells with similar inclination shorter intervals and were able to derive the expected friction factor to model the right Bottom hole assembly (BHA) with iterations to enhance the capability of drilling a long interval without sacrificing the well stability or directional control to overcome the drilling challenges.

The section length was planned to drill 950ft though the reservoir and so, BHA was designed to have a mud motor to control the directional profile and overcome the high downhole torque expected +/- 6,000 ft-lbs and the sinusoidal buckling was 7k lbs WOB.

The bit selection played an important rule to choose the right PDC bit with the optimum cutter's distribution and rake angle for more aggressive cutting efficiency to drill with the minimum WOB applied.

The reservoir pore pressure and fracture gradient were also derived from the nearby wells to decide keeping optimized mud weight and Rheology for high permeable depleted limestone zones while drilling in azimuth 117º near to the least stress direction in the field.

All the drilling and subsurface challenges were sorted and analyzed with an engineered solutions techniques to overcome and deliver the well to the planned TD at 19,000ft MD with total section length of 956ft meanwhile, keeping an optimized drilling parameters and mud rheology to drill the maximum reservoir exposure in a super slim high angle 76º trajectory.

This paper provides an overview regarding the preparations on how to drill a high angle well profile in a super slim 3-7/8in hole size and how to overcome the challenges in terms of the buckling limit and the narrow channel of a mud weight range using a solution engineering solution technique and how the execution was taken to fulfill the subsurface reservoir requirements.

First time in Kuwait for assigned direction company to drill a long 3-7/8in super slim deep well. Differential sticking hazards were addressed by geomechanical modeling for the depleted reservoir to decide the mud weight window for optimum hole cleaning, Stabilizing the underbalanced formations and controlling the ECD following the best practice for hole cleaning in addition to the usage of the mud motor to overcome the low buckling limit and develop a direction control on the well profile.
Adapting to the Increasingly Stringent Coiled Tubing Inspection Requirements
Authors: Jamoussi Anouar
Published: November 2024

Higher expectations for safety, well integrity and Coiled Tubing (CT) string durability have resulted in increasing demand for periodic inspections and continuous monitoring of CT strings. As such, leading companies in the Middle East are requiring more stringent inspections. In this paper, we outline the challenges presented by stricter inspection requirements amid the recent trend for heavier walled strings. We also discuss the engineering solutions we employ to address these new challenges and share concrete results that proved effective.

The new inspection requirements go beyond the stringent API-5ST-SR37 specification for new CT strings. The trend towards heavier wall thickness in CT strings makes the new specifications even more challenging as this increases the separation between the external inspection sensors and any internal flaws. This separation degrades the sensitivity of the inspection tools to internal flaws. To address these challenges, we revamped our CT inspection and continuous monitoring solutions. Specifically, we have developed the following solutions: A new software version for our ECTAS III inspection system with advanced signal processing algorithms that improve sensitivity to difficult flaws, such as narrow longitudinally oriented mass losses on the outer or inner tubing surface.Significant hardware and software enhancements to our continuous, real-time CT monitoring system.

These enhancements yielded significantly better results as proven by data collected upon scanning third-party certified reference standards. These standards come from CT samples supplied by various mills, are EDM machined with reference flaws and independently certified according to industry specifications that we aim to comply with.

We share the performance results of the scans through plots depicting the Magnetic Flux Leakage (MFL) response of the reference flaws. The results show an increase in tool sensitivity to flaws evidenced by a minimum increase of 63% in the signal to noise ratio (SNR) across key reference flaws. This increase in the SNR depends on the wall thickness of the reference standard as well as the flaw geometry.

Our results show that our probability of detection (POD) has improved dramatically. We are now for the first time able to detect the most difficult reference flaw of the new specifications: the longitudinal inner diameter (LID) flaw. The results highlight the unprecedented achievement of a minimum SNR of 3 to 1 on LID flaws in tubing 2 3/8 inch in diameter and up to 0.276 inch in wall thickness. Our technological improvements have ensured continuation in meeting industry requirements amid challenging changes in CT specifications. We continue to contribute to leading CT operators’ endeavor to ensure higher CT quality, enhance safety and drive operational excellence.
Downtime Avoidance and Inspection Optimization Towards AI Implementation (Online Robotic Inspection)
Authors: Oktawira H. , Alkhoujah K. , Hussain H. R. , Alharbi M.
Published: November 2024

ADNOC Sour Gas is dedicated to driving innovation and growth that will improve our business and operation performance; by leveraging robotic technologies or artificial intelligences, thereby optimizing overall inspection activities by eliminating the needs of conventional inspection technologies which require extensive scaffolding, manpower, and downtime/ plant shutdown. The impact of such applications extends to maximizing the assurance levels on health, safety, and environmental (HSE) measures, by eliminating the requirement for the workforce to enter tanks and accordingly minimizing potential risks. Three (3) storage tanks were chosen for this project. The result was satisfactory, and the technology will revolutionize inspection practices in the near future.
Geological Carbon Storage in Saline Aquifers: Factors Governing Residual & Solubility Trapping
Authors: Kumar V. , Ren G. , Talabi O. , Misra S. , Odi U. , Silver A. , Gupta A. , Temizel C.
Published: November 2024

Carbon dioxide (CO2) storage in saline aquifers holds offers a promising solution for mitigating greenhouse gas emissions. Deep saline formations are considered optimal for CO2 storage given their substantial capacity. This study examines the research on the two primary trapping mechanisms, solubility trapping and residual trapping, which are essential for the secure and stable containment of injected CO2 within saline aquifers. Solubility trapping and residual trapping are rapid and pervasive mechanisms in CO2 storage within saline aquifers. A simulation-assisted sensitivity analysis was performed to investigate how various reservoir characteristics, fluid transport properties, and engineering parameters affect the spatiotemporal evolution and interactions of these two trapping mechanisms under diverse geological, fluid, and engineering conditions. Residual trapping becomes the dominant mechanism for long-term CO2 storage, with volumes generally doubling those of solubility trapping after 50 years of monitoring, even though solubility trapping initially surpasses residual trapping at the end of the injection phase. Water imbibition post-injection notably enhances residual trapping, which more than doubles with an injection rate increase from 1 MMT/y to 10 MMT/y. Initially, higher porosity aquifers have high solubility trapping, but this shifts to significant residual trapping as injection continues and ends. Temperature significantly impacts CO2 residual trapping, with a six-fold increase observed at 40°C after injection. Thicker aquifers exhibit pronounced post-injection residual trapping increases, contrasting with stable solubility trapping levels. High-pressure aquifers maintain higher levels of residual trapping, especially noticeable 15 years post injection. Aquifers with high pressure, high permeability, high anisotropy and low temperature show a drastic increase in residual trapping after injection concludes, highlighting their important role in long-term, stable CO2 storage.
Silver Lining in South-East Asia's Decommissioning Industry: A Red Carpet for Service Providers
Authors: Mishra Shubham , Modi Amanpreetsingh , Vasquez Martha , Selem Ahmed M.
Published: November 2024

With over 50 years of sizeable offshore developments, South-east Asia (SEA) has become the next hotbed for the oilfield decommissioning industry. It is estimated that more than 200 offshore fields in SEA will stop producing by 20301, comprising more than 1,500 platforms and ~7,000 wells2–3. With such a large number of "decommission-ready" assets, the total decommissioning costs are estimated to range from $30 billion to as much as $100 billion2–3.

Starting with a large internation oil company (IOC)'s limited decommissioning work in Brunei towards the end of the 1980s, Malaysian national oil company’ first decommissioning in 2003, and Thailand's focused attempts recently at decommissioning it's large assets3, the industry has been evolving at a slow pace in the region and this has created a significant backlog of "decommission-ready" assets adding to the already high liabilities. A combination of complexities and challenges has led to the buildup of this backlog.
New Statistical Approach to Study How an Electric Submersible Pump Population Improves Mean Time Between Failure by 42% in an Ecuador Field
Authors: Andagoya. C Kevin I. , Hidalgo. D Mario H. , Villalobos Jorge L. , Sotomayor Alejandro , Orozco Andrés , Pancho Juan , León Fernando , Reyes Carlos , Enriquez Luis
Published: November 2024

In any electric submersible pump (ESP) population, key performance indicators (KPIs) such as mean time between failure (MTBF), index failure, or run life (RL)/target run life (TRL) are used to keep track the performance of an ESP population. However, what should the stakeholders do in case these metrics decay? In this paper, we introduce a new systematic approach to accurately use population statistics to identify the causes affecting the RL performance so actions to solve them can be taken. The overall approach is to perform a deep analysis of the metrics and detect the causes affecting the RL in a population. A step-by-step statistical analysis aims to segregate the studied population into quadrants. The quadrant range is dependent on the desired TRL of the project or key run life (KRL). Four quadrants are defined, and each quadrant is studied independently using box-and-whiskers plots to learn from them to set accurate actions. Equipment can fail due to the same general reasons; however, this method will study the different root causes and will be digested using different kinds of graphs. This methodology has been used for two consecutive years, showing good results in terms of MTBF on the studied field by increasing it 42%.
Critical Success Factors for Preventing Commissioning and Start-Up Schedule Overrun in Megaprojects
Authors: Elarafi M. G. , Malik N. , Abu A. B.
Published: November 2024

Oil and gas megaprojects are unique, associated with high execution cost and long execution schedules. The Commissioning and Start-up (CSU) delivery of such projects in offshore environment is a complex task. This is mainly because of harsh offshore environment, logistics limitations, integration with producing fields, uncertainty in subsurface data, design flaws, construction errors, etc. This paper analyzes the actual delivery of CSU in offshore oil and gas megaproject. In addition, it shares with the industry the best practices, mitigations, and recommendations for adoption.

A series of Root Cause Analysis (RCA) sessions were held with subject matter experts (SMEs) from different disciplines and stakeholders such as engineering, operation, reliability, commissioning, and vendors. Moreover, statistical analysis was conducted on the RCA outcomes to categorize them by relevancy. The root cause categories are feedstock composition changes, engineering flaws, construction errors, manufacturing defects, human errors, and inadequate maintenance. In addition, these categories were further rationalized and coupled with schedule analysis to understand the impact of each root cause category on CSU schedule. Finally, insights were drawn from this analysis in the form of project management lessons and best practices.

It is worth noting that the offshore execution of this project took place during the peak of COVID-19 pandemic. The productivity, resources mobilization, and material delivery were heavily impacted due to global lockdowns and changing standard operating procedures imposed by authorities to control the outbreak. The impact from COVID-19 was considerable during the offshore construction phase, which is alternatively known as hook-up phase prior to achieving Ready for Start-up (RFSU) state. It is because the construction progress heavily depends on labor, unlike the CSU progress post RFSU which heavily depends on the actual feedstock properties, design quality, and construction quality. Therefore, the impact from COVID-19 was neglected in this analysis because the paper focuses on the performance of CSU post RFSU.
Feasibility Study of Cryogenic Rotating Packed Bed (RPB) Innovation for Acid Gas Removal in LNG Processing – Design Perspective
Authors: Zamry Ts. Nur Baizurah M , Surmi Ir. Ts. Amiza , Mokhtar Ir. Saiful Anuar M , Tahir Ts. Norazliza Md , Umar Ts. Nurul Amirah Hanim
Published: November 2024

The global demand for gas production is rising rapidly due to economic growth, with the Asia Pacific region among the highest contributors. To meet this demand, innovative technology like the Rotating Packed Bed (RPB) operated at cryogenic conditions is being explored and studied for application focusing on acid gas removal in Liquefied Natural Gas (LNG) processing on floater topside. This study delves on 30% CO2 gas field with high H2S and ethane composition via cryogenic technologies with comparable separation capability as conventional amine-based technologies. The main methodology involves detailed process simulations and benchmarking with conventional commercial floater design as basis for technology scale up. Amongst key challenges regarding cryogenic RPB design on a floater are non-conventional acid gas removal process, plot space constraint, energy intensity, and technology scale-up. This study also highlights the potential improvement of cryogenic RPB design in optimized refrigeration schemes and careful evaluation of heavy hydrocarbon recovery. Overall, the successful implementation of cryogenic RPB design optimization for acid gas removal is crucial to unlock monetization of high CO2 gas field(s).
A Novel Approach to Predict the Performance of All Types of Reservoir Fluids from Heavy Oils to Dry Gases
Authors: Shetia Mohamed Ahmed Taher , El Ela Mahmoud Abu , El-Banbi Ahmed H.
Published: November 2024

This study presents a new approach to predict the production performance of wells producing all types of reservoir fluids, including volatile oils and gas condensates. The developed approach combines the general material balance equation, inflow performance relationship, pseudo pressure calculation, and instantaneous gas-oil ratio equation. Using this approach, an integrated model has been developed to simulate the behavior of oil, gas, and gas condensate reservoirs. Furthermore, a genetic optimization algorithm was used with the integrated model for history matching to estimate the original oil/gas in place, productivity index, and saturation and pressure change with time. The developed model can also be used for production forecasting and reserve estimation. Moreover, it can predict well flowing bottomhole pressure, fluid rates, and reservoir pressure over the reservoir life using only the initial reservoir pressure and some production history. It should be highlighted that the developed model considers several drive mechanisms, including gas cap, depletion drive, and rock and fluid expansion.

The integrated model was validated using fourteen reservoir simulation cases with different fluid types (three cases: black oil reservoir, five cases: volatile oil reservoir, five cases: retrograde gas condensate reservoir, and another case: wet gas reservoir). A field application was then used to demonstrate the model's ability to handle actual field data and predict reservoir performance. The results demonstrated a high level of accuracy and agreement between the results of the simulation cases and those of the integrated model. The errors between the results of the simulation cases and the results of the developed model in all cases were less than 1%. Moreover, the developed model will save time and effort considering that the interface of the developed model is user-friendly and the required input data is limited compared to the numerical simulation applications.

The novelty of this study is that it replaces previous forecasting efforts that apply to only limited ranges of reservoir fluids with a new approach that applies to the full range of reservoir fluids, including gas condensates and volatile oils.
Agile Development of Upper Shuaiba Field in North Oman: From Opportunity to First Oil in Under Two Years
Authors: Huisman Selma E. , Al Badi M. , Al Harthi A. , Maqbali H. M. , Al Rahbi Sataa S. , Al Khusaibi M. , Al Hinai M. S.
Published: November 2024

The Upper Shuaiba formation, located in the North of the Sultanate of Oman, consists of complex clinoform structures characterized by their depositional patterns and lateral facies variations. Despite numerous penetrations from lower hydrocarbon-bearing zones, its commercial discovery occurred in the early 2000s. Subsequently, multiple Field Development Plans (FDPs) were formulated to support the development of the Upper Shuaiba fields. Recognizing the potential for standardized and accelerated maturation, a comprehensive Standard FDP was constructed, facilitating efficient development through predefined guidelines.

The Phase-A development of the best and thickest rudist clinoform in 2019, using horizontal waterflood linedrive, laid the groundwork for subsequent phases. Phase-B, initiated in December 2022, aimed to achieve Final Investment Decision (FID) by November 2023. The maturation of Phase-B focused on determining the number of wells to be drilled, with all other decisions being predefined or governed by standard FDP rules.

Several subsurface risks were identified, including facies distribution, reservoir geometry and thickness, and seismic resolution. The "appraise as you go" philosophy ensured each development phase was contingent on appraisal results, providing flexibility in decision-making.

The standard FDP prescribed rule-based well spacing and orientation, considering factors such as rock type, average permeability, net thickness, and stress regime. The operating strategy emphasized maintaining an instantaneous and cumulative voidage replacement ratio of 1.0, with injection operated under matrix conditions to prevent hydraulic fractures.

Standardization extended to well types and completion designs, with the Basis for Design describing a phased evacuation scheme centered around a Remote Manifold Station (RMS) and satellite stations. Rule-based production forecasting, integrating Phase-A results and analogue well data, guided development planning and ensured economic viability.

Non-technical aspects, including agile working methodologies, a scaled Opportunity Realization process, and a commitment to continuous learning, were critical to the project's success. Synergies with nearby fields further optimized resource utilization and accelerated development.

This paper highlights the streamlined decision-making process and key enablers for the agile development of the Upper Shuaiba field, demonstrating how standardization and innovation contributed to the timely achievement of FID and first oil production.
The Next Generation of Autonomous Inflow Control Device (AICD) for Water Control in Light Oil Applications
Authors: Voll B. A. , Edwards L. , Moradi M.
Published: November 2024

This paper presents the design and qualification of a new autonomous flow control device (AICD) for fluid control at the sand face. This device has the unique ability by taking advantages of both density and viscosity differences of the fluids. It controls the flow of the undesired fluid (water and gas) and avoids any binary (open/close) effect that can result in instability or worse stop production. This device is specifically designed to control water production in ultra-light and light applications and to further improve control of gas production.

This new generation of AICD has been developed to enhance control of water by slowly throttling back as the water cut increases while avoiding closing prematurely at a certain water cut. Additional operational features such as last-minute capacity change, and the ability to circulate to the bottom have also been incorporated into the design for ease of installation and providing flexibility and adjustability even at the rig site.

The device is designed to have an operating point towards open for oil and towards closed for water by careful force field analysis confirmed by single and multi-phase flow testing. Water, oil, and gas mixtures were tested in a state-of-the-art multi-phase loop to fully evaluate and model the flow behaviour under various regimes.

Although not limited to oil viscosity, so far, the device shows excellent performance with oil viscosities as low as 0.5cP tested together with water to define the operating and control points at various water cuts. A full qualification matrix of debris, erosion and cycle testing was also completed and will also be presented in the paper.

The available autonomous inflow control devices/devices in the market are not very effective at controlling water when oil viscosities are below 1cP in many applications. Also, another drawback is the possibility of becoming a "binary" open-close system and shutting off zones too early. This new device addresses both the above phenomena.
Novel Blue Hydrogen and Transportation Process Supporting Global Carbon Footprint Reduction
Authors: Rabie A. H. , Alwahedi Y. F. , Ciotti B. G. , Anguiano J. A. , Merryfield D. L.
Published: November 2024

With the imminent threat of global warming, the international energy industry has sought out alternative fuels to reduce greenhouse emissions. Hydrogen, a clean fuel, has been identified as a promising alternative to carbon-based fuels. When utilized, hydrogen produces no harmful exhaust emissions. Blue hydrogen, also known as low carbon intensity hydrogen, is generated via the reaction of hydrocarbons and steam under heat and pressure [steam methane reforming (SMR)] to create hydrogen-enriched syngas. The hydrogen is then purified via a Pressure Swing Adsorption (PSA) unit. The blue hydrogen production process includes carbon capture, utilization, and/or storage technologies.

In this paper, a proprietary blue hydrogen production process is presented. This technology offers certain valuable differentiators described further in this paper. The proprietary process integrates the waste heat from the hydrogen generation process with the heat demand from the carbon capture process. The heat integration scheme is optimized resulting in no auxiliary boilers or drastically reducing auxiliary boiler capacity for the carbon capture process, reducing CAPEX and OPEX. Moreover, the design reduces the footprint of the facility and increases CO2 capture efficiency by eliminating or reducing the boiler's carbon footprint.

Hydrogen transportation and subsequent use is also reviewed. Hydrogen suffers from a low density even in liquid state. As such, the use of chemical carriers is necessary for practical transportation. Ammonia is the predominant chemical carrier for hydrogen as its transport via maritime vessels is well-established. Nonetheless, the use of ammonia as a chemical carrier entails additional processing. Ammonia production predominately uses the Haber-Bosch method, an exothermic process. Upon transportation to the end user, hydrogen recovery is achieved via catalytic cracking of ammonia over a ruthenium or a nickel-based catalyst. Direct combustion of ammonia in maritime vessel engines is also feasible but requires high pressure ratios or the use of co-fuels.