bluuebunny/crossref_metadata_2025 huggingface dataset:
A Case Study on Enhanced Top of Cement Predictive Modelling Validated Against Bond Logs
Authors: Sierra Natalia Leon , Fechner Fara
Published: November 2024

To comply with requirements of local regulations, challenges can arise when cement operations do not go as planned and cement does not circulate to surface. A coal seam gas (CSG) operator in East Australia requested validation of the top of cement (TOC) in three wells (Wells A, B, and C). This was attributed to losses during cementing with uncertainty related to wellbore geometry or a combination of the two. Having the correct TOC estimated with pressure map correlation could help ensure an effective barrier was in place.

Post-job data was gathered and collated as inputs for each well for software simulation. Data included wellbore parameters from drilling data, fluid properties, volumes and rates of fluids pumped, and returns measured in trip tanks and on job pump data acquired for pressure mapping. Iterations were simulated based on the cases until accurate pressure mapping was observed. For Well A, pressure matching calculations between the design and execution phases had iterations in calliper hole size, expected loss zones, and loss rate/volume based on what was observed on the surface. For wells B and C, no losses were encountered. No open hole calliper data was available; hence, the uncertainty with regard to the open hole size and washouts were the key variables to iterate.

Software analysis predictions with post-job field data provided the operator with surface pressure comparisons and predicted TOC for these wells. The accuracy of the simulations were within ± 50 m, later confirmed by cement bond logs (CBLs) conducted post-job. Data screening for the inputs, results analysis, iterative requirements, and comparison of simulation results with log data recorded are discussed. For well A, deviation between the prediction and the actual log result was 3 m.For well B, deviation between the prediction and the actual log result was 20 m.For well C, deviation between the prediction and the actual log result was 58 m.

Log validation of software simulation predictions of the TOC provide operators confidence in the accuracy of predictions. This potentially reduces the need for CBL logs and can result in cost savings for operators in addition to increased trust in available cement tools.
Enhancing Zonal Isolation in Total Loss Zones: Advanced Cementing Techniques for Deep Gas Wells
Authors: Quintero E. , Martanto R. , Edgar D. , Masoud R. , Urdaneta L. , Martinez C.
Published: November 2024

Achieving effective zonal isolation across multiple sections in the presence of weak formations is a significant challenge in the oil industry. The objective of this study is to address this challenge by discussing two successful primary cementing operations across total loss zones in deep gas wells.

In both cases, a meticulous approach was taken. The first involved a production casing, drilling from the previous casing string to the target depth, while the second operation was an intermediate casing. Despite encountering total losses while drilling, conventional lost circulation treatments failed, leading to blind drill the section. To address the zonal isolation challenge, a multi-stage cementing technique employing a novel plug and differential valve (DV) tool set was utilized, capable of withstanding pressure up to 3,000 psi. Extensive placement simulations were conducted to optimize mud removal and cement slurry design properties for the three-stage jobs.

The cement bond logs acquired post-operation exhibited excellent results, confirming successful zonal isolation in both cases. Despite encountering total loss zones, the meticulous planning and execution of the cementing process ensured achievement of the objectives. The utilization of the multi-stage cementing technique, coupled with the novel plug and DV tool set, proved instrumental in mitigating losses and enhancing cementing effectiveness. The comprehensive evaluation, including open hole (OH) caliper log assessment and extensive placement simulations, contributed to optimized mud removal and cement slurry design properties, further enhancing the success of the operations. Overall, this study highlights the efficacy of integrating advanced cementing techniques with detailed planning to overcome challenges associated with zonal isolation in weak formations. The successful outcomes of these operations highlight valuable insights that can inform and improve future cementing practices in similar challenging environments within the petroleum industry.

This paper presents a novel approach to cementing operations in challenging formations, particularly total loss zones encountered in deep gas wells. The utilization of a novel plug and DV set, capable of withstanding high pressures, offers a promising solution to enhance cementing operations in challenging conditions, contributing to the advancement of cementing practices in the petroleum industry.
Re-Development of a Forty-Year-Old Brown Field in South of Oman Producing from Five Different Stacked Reservoirs, Resulting in 50% Oil Gain by Doubling Water Injection
Authors: Hinai Mahmood A. Al
Published: November 2024

This paper showcases the impact of doubling water injection rate from 25k bbl/day to 50k bbl/day in a forty-year-old brown field which lead to 50% oil gain. This was achieved by executing activities to redevelop the five stacked reservoirs in this brown field for better reservoir management. The main activities in the field focused on: (1) de-commingling the water flooded reservoirs from the depletion reservoirs, (2) improving the vertical conformance of the waterflood units via dedicated injection through re-completing the injectors to tubing and casing injectors, Long & Short strings, (3) infill drilling to complete the patterns from 5-spot to 9-spot patterns to improve waterflood sweep, and (4) execute WRM optimization activities to increase injectivity in the water flooded reservoirs.

One of the main challenges in wells commingling production form different units is that individual unit's contribution is not well understood, particularly when the reservoirs have different rock and fluid properties and under different drive mechanisms. Furthermore, there is not much control on each unit production/injection contribution when they are commingled. Therefore, a re-development plan calls for de-commingling production/injection and further infill drill wells to have better understanding and control on the individual unit performance. This approach improved the conformance of the five reservoir units, hence injection and production. Despite the challenges related to urban planning, surface capacity and the ongoing drilling activities, the executed activities resulted in a step change in managing the five different reservoirs, 50% oil production gain, 100% increase in injection as well as new production data from dedicated individual units for the first time from this old brown field. In summary, improving reservoir management through de-commingling waterflooded reservoirs as well as further infill drilling and change in water injectors completions resulted in a step change in the ability to inject water and hence production growth.

The new development has opened further opportunities to continue developing reservoir units that used to be commingled resulting in reserves additions up to 10% of total field reserves. Furthermore, new approach is followed to produce the extremely high viscos oil of a reservoir by commingling, at surface, with nearby producers to ensure produced water pushes the extremely high viscos oil from the wellhead to the station.
Carbon Dioxide Site Storage Monitoring Using Cosmic Ray Muons
Authors: Steer C. A. , Ramsay T. S. , Thompson L. F.
Published: November 2024

Climate change drives a global need to decarbonise and reduce emissions of CO2 into the atmosphere. Carbon Capture and Storage (CCS) is a critical technology that enables countries to undergo a fast transition to net zero emissions. The development of efficient and effective carbon dioxide storage involves the act of liquifying and storing carbon dioxide in natural geological reservoirs. As the dense phase CO2 is injected, deep underground, into a suitable storage site it will naturally pool underneath a capping layer, and develop a plume.

However, there are many regulatory and other factors which means that simply injecting CO2 into the sub-surface isn't sufficient. Of utmost importance is the need to assure public and operator confidence in the entire CCS process. Notably this also means that the CO2 is, indeed, effectively captured and is not passing through the subsurface and re-entering the atmosphere. Conventionally such monitoring takes place episodically via technologies based on seismic sensing, this paper introduces the first results from a novel monitoring approach which uses muons - naturally-occurring radiation - to provide continuous density information of a CCS plume post-injection. Results from the world's first use of this muon imaging technology in field trials in Norway in summer 2023 will be presented and compared with data from traditional seismic measurements that were executed concomitantly.
Compartmentalization, Complex Filling History and Operational Oil Alteration Due to EOR Processes Revealed Using State-of-the-Art Multivariate Geochemical Fingerprinting in a Mature Abu Dhabi Oilfield, UAE
Authors: Koksalan T. , Khan K. A. , Salahuddin A. A. , Aljneibi N. M. , Alblooshi M. N. A. , Adams J. J.
Published: November 2024

The studied Abu Dhabi onshore field, characterized by over 60 producing horizontal wells, has undergone extensive hydrocarbon recovery through miscible HC-WAG, CO2-WAG, and CO2-EOR techniques for more than 15 years. The field’s recent expansion includes delineation wells like X-194 and X-196, drilled to appraise potentially separate oil pools to the west and confirm structural integrity and reservoir continuity. This study leverages oil fingerprinting technology and geochemical data to evaluate the fluid connectivity between the main field and these step-out wells.

X-194, located 9 km west of the main pool, targets an up-dip trap potentially charged from the main field via a fill and spill mechanism. Conversely, X-196, situated 6.5 km southeast of X-195 and 4.5 km west of X-3, probes a different fault block with distinct pressure regimes and free water levels (FWL). The wells, perforated in subzones BII and BIII, target higher subzones due to the positioning of the FWL, with X-28 being the sole well perforated in the lowest BIV subzone.

The study focuses on high-resolution gas chromatography (HRGC) analysis of nine produced oil samples, collected from the two western step-out areas, the field’s crest, and adjacent wells across the fault. These moderate-maturity black oils, with API gravity values ranging from 37 to 39, exhibit geochemical similarity to oils from the main field, with slight variations in thermal maturity suggesting compositional grading.

Findings reveal that oils from the southwestern part of the field, closest to the FWL, display the lowest thermal maturity due to charge stacking, and have been affected by WAG operations. The reservoirs exploited by X-196 appear disconnected from the main field reservoirs, yet share genetic similarities with nearby oils, suggesting a common origin within the petroleum system. X-194’s oil, slightly less mature than its closest counterpart in the main field, supports the hypothesis of a fill and spill scenario but lacks evidence of fluid connectivity to the main field.

The study concludes that while there is a genetic link (i.e., common oil-source relationship) between the step-out wells and the main field, fluid connectivity among the areas is limited. We recommend further integration of geochemical data with reservoir and production dynamics to enhance the understanding of fluid distribution and recovery strategies in the field.
Critical Evaluation of API Free Water Test Addressing Gaps in Lightweight Cement Slurries Testing
Authors: Mahmoud Ahmed Abdulhamid
Published: November 2024

The American Petroleum Institute (API) free water test is a standard procedure designed to measure the free water content in cement slurries. However, this study identifies significant limitations in the API free water testing procedure, especially for cement slurries with very low densities achieved by adding excess water beyond the API's recommended limits. The investigation involved comparing the results of the standard 2-hour API free water test with an extended 24-hour test. The results revealed that for low-density slurries, the 24-hour samples showed a substantially higher amount of free water compared to the 2-hour API test results, the samples showed no free water after 2 hours of testing were experienced significant reduction in the cement column after 24 hours. This discrepancy indicates that the 2-hour API test fails to accurately capture the increased free water content in these slurries. The presence of this additional free water significantly reduces the effective height of the cement column. These findings highlight the inadequacy of the current API free water test for low-density cement slurries and suggest a need for a reassessment and possible modification of testing standards. This study offers a critical evaluation of the API free water test, emphasizing the importance of extended testing durations for lightweight slurries to accurately capture free water content. It suggests improvements and medications to the current testing procedure to make it more reliable and effective, thereby enhancing well cementing operations and ensuring better performance in well cementing.
Rapid Mass Level Organizational AI Sensitization and Skill Development Using No Code AI Tool
Authors: Chowdhury K. A. , Kawsar S. , Imam T. I.
Published: November 2024

The current data-driven digitalization in the oil and gas industry offers opportunities for enhanced safety, efficiency, and significant financial benefits. It supports the transition from a labor-intensive business model to a technology-centric one. However, this shift can introduce high-skill digital labor demands, substantial technology adoption, in some cases lead to disenfranchisement of existing employee especially where artificial intelligence (AI) is utilized. This endeavor implements several AI experience programs using no-code AI technology to quickly sensitize and develop AI skills across various organizational levels.

Four distinct curriculums of 2-hour, 4-hour, 8-hour, and 16-hour durations were developed to provide AI experiences for accomplishing four different skill levels, employee ranges from c-suite executives, regular administrative staff to university faculty and students. The curriculums are designed for non-programmers and non-technical employees, helping them transform real-world problems into AI problems and solve them. Participants gain practical experience in building AI solutions aimed at revenue maximization and cost savings. The learning process is accelerated using a no-code AI tool, which was developed by customizing an automated machine learning Python code to provide an easy-to-use democratized AI interface accessible via a website.

A 16-hour AI sensitization and skill development program was implemented for the oil and gas, power and utilities, financial, government and healthcare industries through university short AI experience program. A survey conducted among non-IT, non-programmer participants showed that 61% reported significant transformation in AI understanding, 81% found the program relevant to their industry’s challenges, and 86% gained confidence in solving AI problems independently. The skill development program was also applied in the oil and gas industry through 2-hour, 4-hour, and 8-hour programs to quickly develop AI skills.

The novelty of this training program lies in the use of no-code AI technology, which eliminates the need for high-tech AI adoption, tedious programming learning processes, and computer science degrees. This approach allows for rapid mass-level AI sensitization and cultural transformation within the oil and gas industry, enabling more effective operation of AI related endeavors and AI implementation throughout organizations. Recent, introduction of generative AI into this technology provides personalized learning experience based on employee’s domain expertise.
An Innovative Approach for Optimizing Remedial Cement Squeeze Operation with a Mechanical Port Collar
Authors: Munoz Julio C Guzman , Aldejani Abdullah M , Alkhaldi Abdulmohsen F , Hasan Muhammad , Allam Belal , Mumtaz Saad
Published: November 2024

This paper aims to spotlight the distinctive approach of utilizing port collar technology in remedial cementing operations, focusing on its unparalleled ability to significantly reduce rig time, optimize operations and increase efficiency. It will be discussed in detail the operational sequence, showcasing the merits, and highlighting the substantial time-saving benefits of this ground-breaking approach.

Total loss circulation is a common occurrence in various fields where depleted or fractured zones are encountered while drilling. In such cases, conventional cement job cannot ensure a good cement across the entire liner/casing. Therefore, remedial cement squeeze job is performed to ensure well integrity in case of total losses. Conventional remedial cement squeeze operation includes the following: running the liner without setting liner top packer, doing the conventional cement job to the loss zone, then run a drillable cement retainer above the liner top to perform cement squeeze operation, afterwards drill-out the cement retainer, run a polish mill and finally deploy liner tie-back packer. Thus, a conventional remedial cement squeeze operation has a lot of complexities and extended operations days. The proposed methodology with the port collar has proven to have significantly minimize rig days and reduce the number of trips to only one. In this operation, a port collar is placed below the liner hanger. The process includes setting the liner hanger, executing a conventional cement job to the loss zone, setting the liner top packer, and subsequently pulling out of the hole. Running in hole with an inner string tool to open the port collar and efficiently squeeze cement into the loss zone, ensuring a controlled and swift operation to ensure well integrity.

A comparative analysis has been performed for both approaches where few wells have been studied in detail. The implementation of Port Collar approach for squeeze cementing has demonstrated a drastic reduction in rig time. Moreover, the compelling comparative results and observations derived from the jobs conducted will be discussed in detail. Furthermore, the unique benefits of the port collar being full bore with no drill out requirement, possibility of multi open and close cycles with metal-to-metal seal and contribution to well integrity have been highlighted and discussed.

Emphasizing a unique approach to squeeze cementing, this paper provides novel information to the petroleum industry. By offering a fresh perspective on time-saving strategies, this paper contributes valuable insights that can reshape existing industry practices and advance the state of knowledge in drilling, ultimately fostering more cost-effective and efficient well integrity solutions.
Most Rigorously Tested Liner Hanger Ever? - Expandable Liner Hanger with All Metal-To-Metal Seals Qualified as Primary Well Barrier, Optimizes Well Design and Enables Production Rate Increase
Authors: Rice J. K. , Chuvas R. de. C. , Lazaro A.
Published: November 2024

The Brazilian Pre-salt fields have driven technology developments and casing architecture advancements1 over the past 19 years. In 2023, Petrobras challenged the industry to design, test and build a liner hanger to meet the extreme requirements of their Buzios field 5 section well configuration2 which requires a high-capacity liner hanger to provide the interface between 10 ¾ and 14" casing as a well barrier with no tieback to the subsea wellhead. The original intention of this Expandable Liner Hanger (ELH) interface is to be a barrier replacing the cement at the top of the liner (TOL). This well configuration requires a long casing string to be suspended on a liner hanger with the potential for intersecting a fractured zone at the top of the reservoir. Both the length of liner and the fractured zones are challenges to establishing cement integrity at to the top of the liner without the need for remedial cement operations which can be costly and time consuming. The ELH system is designed and tested as a seal at the top of the liner for the full well life without the need for cement. As there were no industry standard testing protocols which effectively simulate the full well life conditions, Petrobras established their own protocol to specify the testing requirement that covers this application. As compared to industry protocols such as API19LH, the Petrobras requirements included rigorous testing related to a much higher number of individual points of applied load and pressure (427 total), a challenging non-metallic chemical resistance protocol, and metallurgy to provide corrosion resistance.

In this improved well configuration, the use of a liner hanger enables a 6 5/8" intelligent completion to be deployed through the reservoir while above the liner hanger a larger 7 5/8" production string is installed inside the 14" increasing the ability for higher flow volumes during production (Figure 1). This casing design considered the full life cycle of the well from an expected initial state of oil production (without water or gas), followed by water/gas breakthrough and production with a mixture of oil, water, and gas. The well design also considered a drop in the reservoir pressure resulting in the bubble point being reached causing a mixture of oil and gas to be produced. The design and subsequent testing protocol establishes a system which is applicable to the Buzios field project and many other fields where the required loads and pressures are within the envelope.

Figure 1 Well configurations showing conventional and optimized well design with 10 ¾ expandable liner hanger
Site Nvgtn Pro: Empowering Youth and Leadership with Safe Site Exploration and Elevated Operational Excellence Using FIT Application and Platform
Authors: Alsenaidi S. A. Shemaisa
Published: November 2024

Our objective is to streamline the identification and evaluation of potential workover candidates in ADNOC's dynamic drilling and workover schedule. We address challenges related to timing issues in email communications and the need for efficient decision-making amidst many rigs. Our platform offers two workflows, involving all stakeholders, to secure well candidates efficiently and ensure seamless technology implementation, fostering operational excellence and comprehensive records for future reference.
Development of the Mozambique Gas Industry - Will Onshore LNG or Floating LNG Production Facilities Most Likely Deliver Profitable Projects for the IOCs?
Authors: Meulengracht C. S. , Djupvik J. A. , Barhate A.
Published: November 2024

Objective/Scope

Since 2010 more than 100 Tcf of recoverable gas reserves have been discovered offshore Mozambique. Large gas discoveries that are distant from markets now have 2 different LNG development solutions. The first is the classical onshore LNG production facility and the second is the offshore floating LNG (FLNG) production facility, a comparatively new development solution. This paper examines both solutions for all fields being developed or planned with both deterministic and stochastic LNG price assumptions.

Method/Procedure/Process

The Rovuma basin now features the Coral South FLNG in production, and the Coral North FLNG and several onshore LNG production facilities are being planned. Gas production profiles and costs including DRILLEX, CAPEX and OPEX are determined for these projects with their foreseen development solutions. Then the same profiles are estimated for the alternative development solutions.

Base case deterministic economic analysis is carried out with detailed after-tax cash flows for all projects using both development solutions. Sensitivity analyses allow for calculating tornado diagrams and break-even values. Where appropriate a portfolio analysis is performed to include the effect of being in tax positions with multiple fields.

In addition, stochastic random-walk LNG price scenarios are applied for all projects, including alternative development solutions. NPVs are then plotted as cumulative density distributions to determine the probabilities of the projects being economical for the IOCs given the LNG price variation assumptions. Cumulative density distributions are also created for the Government Takes.

Results/Observations/Conclusions

The calculated cumulative density distributions are skewed S-shaped curves leading to the conclusion that NPVs are log-normally distributed.

The most important result is that the probabilities for the projects delivering positive NPV given stochastic LNG price scenarios, and therefore providing a minimum return equal to the discount rate, can be determined and compared with other projects and project solutions. Cumulative density distributions for the Government Takes are also be determined.

The strengths and weaknesses of stochastic analysis versus deterministic analysis are discussed.

Novelty/Additive Information

Pure deterministic analysis with sensitivities is excellent for analyzing the robustness of a project, however when supplemented by stochastic analysis deeper insights are achieved.

The novelty of this paper is the application of real project data with two alternative development solutions and then applying stochastic random-walk prices to evaluate the probabilities of being economical. The LNG prices are the most uncertain aspect of an LNG development and have the greatest impact on the economics.
Maximizing & De-Bottlenecking Gas Export with A Sustainable Approach Using Six Sigma Tool
Authors: Al Kindi Zeyana , Al Hadhrami Abdullah , Al Maskari Mubarak , Al Saifi Saud , Bawdekar Mangesh Ashok
Published: November 2024

The implemented endeavor stands as a pivotal milestone in the nation's trajectory towards attaining cost competitiveness and curbing gas emissions, embodying a dual-fold value proposition characterized by both direct and indirect revenue implications. The debottlenecking of the Gas export system, culminating in a notable 5% increase of production in export gas flowrate serves as a direct catalyst for revenue augmentation, synergistically accompanied by a significant surge of approximately 2% in condensate production. Projections indicate a short-term cumulative revenue upswing of up to 10% annually direct revenue (Cash Flow), poised to ascend impressively to 25% of budget increase per annum over the long haul.

Indirectly, the amalgamation of stations and initiatives aimed at skill development underscores a broader spectrum of influence, encompassing the mitigation of excessive flaring, harmonization with low carbon emission targets, and the cultivation of human capital in accordance with national imperatives. These enhancements align seamlessly with Petroleum Development Oman's unwavering commitment to fulfilling SGL supply requisites, thereby bolstering the nation's standing on the global stage.

The undertaking, characterized by a 5% production of gas export amplification, reaffirms the organization's stature as a reliable gas provider, emblematic of its steadfast dedication to enhancing production efficiency. Emphasis on gas emission reduction and energy conservation, epitomized by heightened compressor efficacy and ensuing energy preservation, resonates with renewed HSE priorities.

Moreover, the project serves as a testament to innovation, evidenced by the prioritization of emergent gas technologies and the seamless integration of Six Sigma methodologies. Insights gleaned from this endeavor hold promise for replication across Petroleum Development Oman and Oman, promising streamlined energy utilization and cost mitigation to fortify competitiveness in the forthcoming energy landscape.
Experimental and Numerical Study of Anomalous Imbibition in Shale Gas Reservoirs
Authors: Zhang M. , Sun Q. , Ayala L. F.
Published: November 2024

This paper investigates the phenomenon of anomalous imbibition in shale reservoir rocks through a combination of numerical and experimental approaches. Shale gas reservoirs present unique challenges due to their low permeability and complex pore structure, significantly influencing fluid transport mechanisms. Spontaneous imbibition, where water (or fracturing fluids) infiltrates the shale matrix and displaces the gas driven by capillary force, plays a critical role in the recovery efficiency of shale gas reservoirs. Fluid spontaneous imbibition in heterogeneous porous media, such as tight and shale formations, often exhibits anomalous behavior dominated by multiple time-spatial scales. Based on direct experimental evidence of anomalous imbibition process, this work proposes a fractional derivative model to quantitatively analyze the complete early-to-late time dynamics of the anomalous imbibition in shale gas reservoirs. Prior research on the anomalous imbibition process has primarily focused on fractal models and has compared results with indirect indicators, such as the cumulative imbibed volume derived from imbibition experiments. This study introduces direct observations and quantifications of the anomalous imbibition dynamics, utilizing saturation distributions converted from Computed Tomography (CT) numbers. A fractional diffusion model is proposed, and the resulting non-linear fractional differential equations are solved numerically using the finite-difference method. The proposed model solution accurately captures the complete early-to-late time behavior of cumulative recovery volume and the wetting phase front propagations which exhibit anomalous phenomena.
Data Driven Alarm Rationalization: Implementing Effective Alarm Systems in Oil Field Operations
Authors: Al Shueili H. H. , Al Alawi R. M. , Al Amri A.
Published: November 2024

As the oil and gas industries progressively relying on modern automated control systems to monitor, control and safeguard plants, alarms can be configured with very small effort and high volumes. Therefore, the number of alarms can become overwhelming for the operators dealing with more alarms than the usual. Subsequently, leading to alarm fatigue where important alarms can be ignored or missed. This increases the difficulty of responding to plants' upset which can lead to possible accidents or unplanned shutdowns.

Alarm rationalization is the critical process of analyzing, evaluating, and refining alarm systems to ensure that alarms are meaningful and actionable. This process involves reducing the high number of redundant or false alarms, categorizing them based on their priority, and ensuring that each alarm provides clear and actionable information. The main goal is to minimize unnecessary or false alarms, improve the plant's safety and enhance operational reliability by having the operators focus on the critical alerts.

In this paper, we explore how a data-driven approach was applied to improve alarm systems in a heavy oil field operation. By enforcing the "Alarm Documentation and Rationalization (D&R)" procedure, we developed a robust system that uses data analysis to create an action-driven alarm system. This system is designed to alert and guide operations to corrective actions without causing distraction, confusion, or conflict. We describe the methods, procedures, results, and conclusions of the project, showcasing how it significantly reduced unnecessary alarms and boosted operator efficiency.
A Study on Supply Chain Management of LNG Using Artificial Intelligence
Authors: Susan Koshy Nicy
Published: November 2024

The use of Artificial Intelligence (AI) in the supply chain management (SCM) of liquefied natural gas (LNG) is an important turning point with far reaching impact on the industry. It focuses on how AI technologies can help optimize different aspects of the LNG supply chain such as demand forecasting, inventory control, route optimization and risk management. The study looks into how it facilitates visibility across the entire supply chain, manage risks associated with international sanctions and embargoes and assesses its influence on energy efficiency and emissions. Employing mixed-method approach that includes qualitative interviews, case studies and quantitative analysis, this research provides comprehensive insights as well as actionable recommendations. The findings indicate that AI has potential to revolutionize LNG SCM through increased operational efficiencies, lower costs, and more sustainable/resilient operations.
Should We Worry About Our Field Development Planning due to Compaction Acceleration?
Authors: Bernadi B. , Ferdaos M. , Awadhi F. O. Al , Ameri S. A. Al , Shamsi A. B. Al , Albairaq A. , Ali R. Al , Dhanhani H. Al
Published: November 2024

Reservoir A is a mature carbonate gas-cap field that has been depleting gas for a long time. Reducing the compression pressure can increase the gas recovery. But this can also speed up the reservoir compaction due to higher withdrawals, which can cause subsidence, permeability reduction, wellbore instability, completion integrity, etc. To prevent this, history-matching exercises with Assisted History Matching (AHM) technique are used to investigate the minimum pressure that would start shrinking the porosity.

AHM is a way to find the best values of the uncertain parameters that minimize the mismatch between the simulated and observed data. Objective functions (OF) are used to match the production and pressure within a small defined tolerance. The reservoirs are split into 6 sectors for easier analysis. After doing AHM exercises, the best cases are chosen and various cross-plots are made to see how OF and history-matching variables are related. The cases with the strongest relationships are checked to see if modifying the rock compaction can be the most likely option to improve the history-matching.

In the initial attempt with AHM, the simulated pressure in the southern sector consistently surpasses the actual pressure, whereas the opposite is true for the northern sector, especially in recent times. This discrepancy remains even after adjusting factors such as permeability, fluid contact, reservoir pore volume, and transmissibility during the history-matching process. The variation in pressure might be due to different compaction rates across the gas cap zone. Utilizing two separate rock compaction tables that transition from fast to slow from north to south could potentially improve the pressure matching.

Future reservoir development, either through infill wells or field compression projects aimed at reducing abandonment pressure, may negatively impact the safety and economy of both sub-surface and surface facilities. To mitigate these risks, it is essential to avoid excessive production withdrawal, particularly in regions where a faster rate of compaction could pose a threat.

Compaction acceleration can affect the future development plan of reservoir A, by reducing the recovery factor, increasing the risk of reservoir subsidence, well issues, altering the optimal design of the new wells and the compression system. The study with AHM can help to evaluate how serious the compaction problem is for reservoir A, and it can recommend the need to initiate more sophisticated geomechanics modelling if it is essential.
Longest Lateral Section Drilled in Pakistan with the Underbalanced Drilling Methodology in a Challenging ERD Well in a Naturally Fractured Reservoir Structure – A Novel Approach Toward Innovative Drilling Techniques
Authors: Uzair Qadir Shaikh , Qasim Ashraf , Hassan Raja , Ahmed Qureshi Haris
Published: November 2024

The X Field, located in Sindh on the right bank of the Indus River, contains a shallow carbonate reservoir structure that is present at a depth of about 650m TVDSS. After continual production from the reservoir, the reservoir pressure has been depleted to sub-normal at ~0.6 SG equivalent mud weight (EMW).

While drilling with a conventional mud system encountered total losses and resorted to heavy lost-circulation material (LCM) pills to cure them. All bridging materials pumped in the hole to cure losses invaded the reservoir formation. As a result, the completed well required excessive cleanup operations to bring it into production. Therefore, faced additional costs of loss curing materials, damage to the reservoir formation, and a substantial amount of time for drilling and cleanup operations.

It was planned to look for a solution to not only reduce the costs associated with drilling this highly depleted reservoir formation, but also mitigate invasion damage that inevitably affects overall production. Although underbalanced drilling had been used in similar situations, but the challenges associated with this well were quite enormous. The horizontal well design contained a lateral of about 778m. Challenges to account for while drilling the horizontal leg included designing appropriate directional drilling equipment for use with a multiphase fluid, cleaning the hole in the horizontal leg, maintaining underbalanced wellbore pressures in the presence of high annular pressure loss.

For this reservoir pressure of 0.6 SG EMW, a nitrified foam system was designed to achieve an equivalent circulating density (ECD) below 0.6 SG EMW. This foam system was designed using a formulated polymer system to yield a high foam quality for suspension and cutting carrying capacity. Geosteering was also performed using RSS, EM-MWD and LWD tools in multiphase fluid system to optimize well placement. In addition, a downhole deployment valve (DDV) deployed inside the casing string enabled isolating the live well while tripping. Applying all these innovative methods the drilling of this cumbersome section was completed in just 4.5 days having an avg ROP of 26 m/hr. Most importantly this methodology helped us to achieve zero skin drilling hence resulting in unprecedented production enhancement from this well. The paper outlines the planning and design of this unorthodox well, its execution, and the results achieved.
Reservoir Operating Envelope Recommendations as Input into Limit Diagrams for HP/HT, Complex, Sour Carbonate Reservoirs
Authors: Saffar Al , Abdullah B. , Radha F. , Benkhalaf S. , Aldhoubi E. , Ameer A. , Sabti A. , AlJasmi S. , Emera A. Mohammed , Taheri S. , Nishi K. , Khakmedov Azat , Al Saleh A. , Al-Ajmi A.
Published: November 2024

Reservoir offtake limits can be imposed for fields or certain areas per field or certain reservoirs as deemed necessary for safe and optimized production/operation of a hydrocarbon bearing reservoir. Key reasons to limit the production offtake for a certain field can include: Safeguarding long-term URMinimizing water production, thus avoiding artificial lift or any integrity (corrosion) issuesMaximizing key hydrocarbon phase productionWell, Reservoir and Facility Management (WRFM) purposes

Reservoir offtake limits were established for HP/HT deep Middle Marrat (MM) reservoirs (gas condensate and volatile oil reservoirs) using the dynamic simulation models.

These reservoir offtake limits are the average rates that can be produced without negatively impacting the long-term value (i.e., UR) or short-term excessive water production. With all constraints removed from the dynamic simulators except flowing bottom hole pressure (FBHP) and/or drawdown (i.e., CIBHP – FBHP), these limits reflect the capability of the reservoirs with the current well stock independently of any restrictions in the tubing, choke or back pressures from the facilities.

Thus, these reservoir offtake limits may not be realizable with the current facility/well/choke/flowline arrangement., i.e., for example compression, pumps or artificial lift may need to be installed to deliver these rates. These limits are proposed to maximize the long-term revenue value ($). Next step is to use these reservoir limit into the system limit diagram to determine asset production limit considering all production system (reservoir, facility, well, chokes, and flowline). Output from this work is a list of production rates and constrains including DD limits in order to safely produce the reservoirs.

These analyses helped to support optimizing production from current producing wells in a safe and efficient way which enhance reservoir health and optimize operation envelop. This is a very important part to safely and optimally manage reservoir performance without impacting long term value through determine and reduce impact of any bottleneck in the production system.
Robust Workflow to Assess and Optimize Condensates Recovery from Rich Gas Reservoirs: A Case Study from Abu Dhabi, UAE
Authors: Ojha Aditya , Latypov E. , Sudarev M. , Bernadi B. , Albairaq A. , Alawadhi F. , Mengal S. , Al Shamsi A.
Published: November 2024

Optimal recovery from a rich gas condensate reservoir is always a big question for an E&P operator, wherein the correct choice between prioritizing condensate recovery or gas exports must be made at the right time. This paper discusses a detailed technical evaluation workflow which highlights all the steps required to be executed to make an informed decision towards implementing an optimized reservoir management scheme, through a case study from onshore Abu Dhabi, UAE.

The workflow starts with an in-depth evaluation of available data followed by an exhaustive well screening and candidate selection for extracting sectors from an existing subsurface model. The sector selection process honors the variation of rock properties, wells' performance, expected condensates dropout volumes etc. The next task is to enhance the existing sector models to accurately model condensate drop out and blockage phenomena. The impact of Non-Darcy flow and velocity dependent relative permeability on wells' performance is captured and modeled appropriately. Assessment of the impact of CO2/N2/Chemical injection along with injection volumes & rates on sectoral performance, is made.

The detailed workflow has been used to identify and investigate several reservoir management strategies viz. drilling infill producers, MRC peripheral injector wells, non-HC gas injection, chemical injection etc. Furthermore, the optimized time for blowdown has been identified, precisely balancing the prioritization of condensates recovery along with gas sales.

It has been identified that after ~50 years of production under partial lean gas recycle mode, ~ 27% of the initial condensate in place has already dropped out as liquid in the reservoir, which would increase to ~34% in the next 60 years if the planned reservoir management scheme is not modified.

Appropriate non-HC gas (CO2 /N2) injection schemes along with carefully planned peripheral MRC gas injectors and infill wells, could potentially mitigate the risk of losing precious condensate in the reservoir and increase recovery to 75-80%. A carefully planned chemical injection scheme could also reduce the risk of near wellbore condensate blockage. The proposed development schemes need to go through further evaluation of risk assessment, project economics and piloting phases to substantiate the recovery numbers.
Integrated Approach to Enhance in Low-Performance Tight Reservoir Wells
Authors: Yaqoubi Nouf Al , Mengal Salman , Ojha Aditya , Bernadi Bondan , Shehhi Hajar Al , Morrow Timothy Ian , Agbari Zainah Al , Deshmukh Rohit V. , Almteiri Nama , Bairaq Ahmed Al , Dhanhani Helal Al
Published: November 2024

This paper delves into the establishment of a comprehensive procedure for the evaluation of underperforming wells, alongside an analysis of the present and anticipated future conditions of a significant, onshore natural gas asset located in the United Arab Emirates. The implemented process has brought to light viable opportunities that could significantly enhance productivity. These opportunities include the matrix stimulation of current wells, which is a technique designed to improve the flow of hydrocarbons by removing blockages within the wellbore, thereby optimizing the extraction process. Additionally, the process involves expanding the reservoir contact, which effectively increases the interface area between the well and the reservoir, allowing for a more efficient recovery of stranded potential reserves. This approach is particularly advantageous as it circumvents the need for drilling new wells, thereby reducing operational costs and minimizing environmental impact. The findings from this comprehensive evaluation suggest that by adopting these strategies, it is possible to revitalize existing assets and unlock additional value from the natural gas field.
Application of Generative AI to Derive Insight from Supply Chain & Logistics Contracts
Authors: Singh Ajay , Jia Tianxia , Nalagatla Varun , Cunningham Brian , Siwani Talib
Published: November 2024

Contract management is a critical process for energy companies operating across upstream, midstream, and downstream sectors. These companies deal with numerous complex contracts containing intricate legal language, cross-references, and long document lineages spanning amendments and supplemental materials. Manually extracting insights and managing obligations from these highly unstructured contracts is extremely time-consuming and error-prone. This paper presents a novel framework leveraging machine learning and generative AI (GenAI) to automate and streamline contract management. The proposed solution utilizes large language models (LLMs), prompt engineering, retrieval-augmented generation (RAG), and chain-of-thought reasoning to extract structured data (such as fees, escalations etc.) from contracts, perform analyses, and generate natural language responses. It enables use cases like optionality analysis, fee calculation, cross-contract insight generation, invoice processing, and user feedback integration. The architecture combines LLMs with contract knowledge bases and external data sources to optimize operations, mitigate risks, and enhance decision-making. Key capabilities include centralized repositories, clause extraction, compliance tracking, workflow automation, and advanced analytics leveraging LLM question-answering, summarization, and code generation abilities. The paper discusses technical details, use case scenarios applicable to crude oil transportation contracts in supply & chain, and highlights GenAI's potential to transform energy industry contract management practices. When conducting analyses involving hundreds of contracts, the proposed solution exhibited significant efficiency gains. Case studies showed that it reduced processing time by 10 to 100 times compared to manual methods.