bluuebunny/crossref_metadata_2025 huggingface dataset:
Digital Solution for Well Surveillance in Stacked Reservoirs with Near-Critical Fluid Systems
Authors: Mogensen K. , Mata C. , Samajpati S. , Cremades P. , Uribe J. E. L. , Al Zaabi M.
Published: February 2024

Fully compositional integrated asset models (FC-IAM) are being deployed for an increasing number of fields in the company's portfolio. Field A described in this work comprises four stacked reservoirs, each containing a near-critical fluid system with significant compositional depth gradient. Augmenting the FC-IAM with high-frequency sensor data as well as proprietary tools to actively monitor well performance helps identify and pursue opportunities to maximize the oil production rate from the field, subject to several system constraints.

Fluid properties were modelled with a cubic equation of state tuned to laboratory data to address some key challenges: Near-critical fluid systems giving rise to compositional variation versus depth.Injection of produced gas that develops multi-contact miscibility with the original reservoir fluids.Blending of fluids at surface from four stacked reservoirs.Operational requirement to maintain the bottom-hole pressure above saturation pressure.Validation of raw well test data before shrinkage correction (line conditions).

Compositional surface network models are run automatically on hourly basis and compared against real-time data. A surveillance algorithm identifies opportunities and assigns them to well owners. Activities are managed through a high-level tracking and value-capture system.

The asset team is consistently maintaining the well and surface network models assisted by the digital solution. The surveillance automation engine creates a feedback loop with the engineers which ensures that the models are of sufficient quality for production optimization. Models reproduce the actual oil and gas produced rates within the accepted accuracy range and are used routinely in optimization scenarios. The surface network model is also run in transient mode to study and optimize flow in two large subsea multiphase pipelines. Total value generation from implementation of the complete framework therefore exceeds expectation based on the steady-state production gain. The intangible value associated to reducing engineers’ workload, better data accessibility, HS&E and efficiency of operations has set a strong foundation for the strategy of the company to grow its enterprise value through increased volume and cost reduction.

Implementation of a compositional model framework is still uncommon as most integrated asset models rely on a black-oil formulation for the fluid property description. Near-critical fluid systems undergoing miscible gas injection add an additional layer of complexity in terms of modeling and surveillance efforts. Real-time data have proven indispensable for keeping the IAM up to date and for identifying opportunities for optimizing the production.
Maximizing Production and Cost Optimization in a Remote Carbonate Oilfield through a Standalone Waterflooding System: An Oman North Case Study
Authors: Al-Mamari A. A. , Al-Ajmi M. A. , Al-Omeiri H. N.
Published: February 2024

Oxy's Oman North concession, a remote carbonate oilfield with a gas cap, initially produced under natural depletion, but production declined rapidly due to low reservoir pressure and a weak edge aquifer.

To address this issue, waterflooding was deemed necessary. However, the field's location, which was approximately 50 km away from the main production station, posed a challenge because it would require considerable time and cost to install water injection facilities that are connected to the main station and provide the required produced water for injection. To overcome this challenge, a standalone system was designed with surface pumps for water injection. The project was executed within a year at a cost that was about 25% of constructing a water injection header from the station.

The system's design included horizontal injectors that were aligned to support horizontal oil producers and prevent the encroachment of the gas cap further downdip. Injection optimization and redistribution of water among the injectors were strategies for maintaining high production and helped to control costs, as they ensured that no injected water or energy was wasted without a return of oil. For example, voidage replacement ratio and diagnostic plots were produced on a monthly basis to monitor the injection performance. The surface network was also optimized using Prosper and GAP modeling tools along with day-to-day monitoring. Wells were choked and opened to maximize production for the entire network. The implementation of these best practices resulted in a significant acceleration of field production. Within the first 18 months, production tripled, and then reached more than five times pre-waterflood rates by 2023.

This paper presents an innovative method within the industry that effectively increases production while being cost-efficient. It introduces a pioneering approach that revolutionized production processes, achieved remarkable results, and ensured significant growth in production capacity.
Breaking the Chain, Novel Use of Adaptive Model Approach for Reservoir Modelling Reduces Time Duration of Project and Improves Collaboration
Authors: Thompson A. R. , Bolivar C. E. Zerpa
Published: February 2024

This paper details how the reservoir modelling workflow can be accelerated, and uncertainty reduced even for challenging Green Field prospects by constructing multiple small fit for purpose integrated adaptive models instead of just one all-encompassing model.

Adaptive models are models built with a single purpose as compared to more conventional reservoir models which are designed to be flexible and be used for multiple purposes. By only having a single task, these adaptive models can be built more quickly and since they are used as tool, not the product, they do not need to be reviewed. Multiple different adaptive models are built to handle different questions ranging from production data QC, different facies models going through to local history matches. As the study progresses, these adaptive models can be combined to consider multiple components and their influence on each other to ensure compatibility and to possibly feed information to the modeling effort for the full field model. As the project finalizes, these adaptive models work like jigsaw pieces to come together to create the finalized picture/model.

In the application of adaptive models within an integrated reservoir study, the most obvious benefit is being able to complete the static and dynamic aspects of the model building in parallel and subsequently be able to move more quickly to the deployment of the model for placing wells. Another key benefit was that it was possible to evaluate and defend new concepts or methods in reservoir modeling. Integrating new components into an existing modeling doctrine is challenging as significant time has to be expended and this has to be justified in advance of knowing the impact of the new item. With adaptive models, it is possible to evaluate out of doctrine ideas in parallel and off critical path. If the results are positive, the adaptive model is available to justify the benefit of the change and to also act as a comparison to the result following the doctrine.

This innovative workflow enables more efficient working by reducing the number of items on the critical path while simultaneously improving integration by enabling static and dynamic data to be integrated before the static model is finalized. In addition, this approach is a driver for innovation as it enables new ideas to be evaluated more rapidly and without having to impact the critical path of the project.
An Innovative Model Preconditioning Approach for Fast and Reliable History Matching
Authors: Kayode B. O. , Stephen K. D. , Albeshri R.
Published: February 2024

History matching is the process of calibrating a geological model to match the historical production, pressure and other reservoir characterization data. The methods developed in this work aims to address the history matching problem through an a priori integration of data-derived features into the static modeling phase, using a process we have termed pre-conditioned modelling. The methodology combines data mining techniques with intelligent visualizations to swiftly extract features from historical pressure and core permeability data, and integrate these features a priori into the static model. An anomaly detection algorithm was developed and used to detect data outliers and exclude anomalies from pressure data. A pattern recognition algorithm was developed, used for pressure cluster differentiation, and then to create reservoir regions containing wells within similar time-lapse pressure cluster, and the created regions were used as containers to guide permeability modeling and for applying sub-global permeability updates during history matching. The reservoir's internal architecture was derived from core permeability using a data mining algorithm we developed and termed fixed-window averaging. The intra-reservoir architecture was used to control the static model's vertical heterogeneity trends. This innovative approach to rapidly integrate historical pressure and core permeability dataset features into the static modeling process, resulted in a model that required no significant need for the traditional history-match process because the do-nothing match was excellent. A data analytics algorithm termed spatial Pythagorean search was developed and used to detect the causes of well productivity problems. An advanced visualization interface was developed which allows both time-based (e.g., water-cut, datum pressure) and depth-based (e.g., FTS, PNL, mobility, PTA) parameters to be displayed, permitting fully integrated decision making regarding necessary modifications. Leveraging holistic data visualization and data mining techniques, our methodology helps establish a reliable reservoir model by prior integration of data-derived features into the static model, significantly reducing the time required for history matching.
Wellbore Strengthening Uncertainties and Workflow Optimizations
Authors: Samy A.
Published: February 2024

Drilling depleted reservoirs is a challenging operation due to significant mud losses and potential risk of wellbore collapse against shale or high-pressure formations if mud weight has been decreased to mitigate mud losses across depleted reservoirs. Wellbore strengthening is an efficient and reliable technique to enable a continuous drilling operation for formations with different pore pressures such as drilling depleted reservoirs with the high mud weight required to support shale or high-pressure reservoirs.

If wellbore strengthening has been designed correctly and successfully executed, it could eliminate the total number of casing stages required to drill formations with different pore pressures separately to avoid mud losses or wellbore collapse during drilling. Decreasing casing stages will ensure reaching the target reservoir with larger casing size, thus improving well productivity.

Wellbore strengthening technique includes the initiation of short fractures where bridging particles are used to seal and hold the fractures open and prevent any further propagation inside formation. The hoop stress around wellbore will be increased accordingly and enable drilling such depleted reservoirs with higher mud weights. This paper discusses the methodology and assumptions considered in wellbore strengthening design including fracture propagation and the optimum geometry required to yield maximum wellbore strengthening during drilling. The paper will also propose an optimized workflow to be used as guideline for this application.

Wellbore strengthening design includes two main parts: fracture width opening and particle size calculations. There are many different analytical methods which can be used to calculate fracture width including PKN, GDK, etc. This paper presents a case study where all methods were screened and compared to the results of a pseudo-3D fracture propagation model. The most appropriate and reliable analytical method to calculate fracture width distribution inside formation during wellbore strengthening has been identified for complex geomechanical environment such as stress anisotropy field.

Fracture half-length is usually assumed in wellbore strengthening design to allow the calculations of fracture width. This assumption is not always right, it is associated with high degree of uncertainties and may not represent the optimum fracture geometry. This paper discusses a new design approach where fracture geometry can be optimized including the optimum ratio between invaded and non-invaded zones and the optimum fracture geometry required to maximize wellbore strengthening during drilling depleted reservoirs. A robust, reliable, and optimized workflow is also suggested in this paper to ensure that all uncertainties associated with wellbore strengthening design have been considered and addressed.
A Bayesian Optimization Workflow for Integrated Asset Management Under Uncertainty
Authors: Taha T. , Abdallah M. , Shabani M. , Gringarten E.
Published: February 2024

To improve production under existing facility operating constraints, while minimizing emissions and energy consumption, operators today are looking for workflows that integrate surface and subsurface models as a foundational pillar of the digitalization of oilfield operations.

In this work, we investigate the investment and operational planning of a multi-field asset development under uncertainty. Our solution is an integrated workflow for scheduling, forecasting, and optimizing the multi-field asset across the entire value chain, from the subsurface reservoirs to delivery to market.

Our integrated operation and optimization workflow example consists of one gas condensate and two oil reservoirs models, coupled to a common production surface network model, itself connected to a processing facility model, together with an economic model. Consistent PVT properties have been used throughout the system. The thermo-hydraulic performance of the production network is modelled using a drift flux based mechanistic approach. Operational constraints are honoured on wells, surface network, and processing facility.

Our proposed solution is built in a commercial integrated asset management platform that connects the models and orchestrates their execution and optimization.

We have successfully integrated the subsurface, gathering systems, and surface facility models. This integration has allowed us to better understand the behaviour of the field and optimize its operation. By combining data and workflows across multiple disciplines, we can make informed decisions more efficiently and more reliably and mitigate risk with confidence.

Bayesian optimization offers an alternative solution to traditional ensemble methods by using probabilistic surrogate models that can capture and propagate uncertainties from multiple disciplines without the need for large ensembles.

The solution is equipped with unified analytical and diagnostics dashboards for the multidisciplinary technical asset team including management for decision making under uncertainty.

This is a truly part of a digital twin of the oilfield with improved asset management under uncertainty in the era of digital transformation.
Unveiling the Stability of Modified Graphene: Insights Through Visual Observation and Light Scattering Technique
Authors: Murtaza Mobeen , Rana Azeem , Kamal Muhammad Shahzad , Alarifi Sulaiman , Mahmoud Mohamed , Saleh Tawfik A.
Published: February 2024

Graphene is an extraordinary two-dimensional material that demonstrate the application in various field, including utilization in the drilling fluid for the friction reduction and fluid loss control. However, the drilling fluid applications of graphene are limit by its tendency to settle over the time, that tremendously reduced the efficiency of the drilling process. In order to overcome the settling effect, the modification of graphene could be employed. In the current study, the electrochemically exfoliated graphene modified by incorporating Gum Arabic to improve the aqueous suspension stability in water. The transmittance and backscattering measurements were assessed over time to analyze the stability of the graphene dispersion. The stability indices obtained from the transmittance and backscattering profiles provide quantitative comparison of settling rate of the modified graphene with that of unmodified counterpart. The experimental outcomes of light scattering technique (LST) and visual observations revealed the lowering of settling problem and the improvement in the dispersion features of the drilling fluid. The assessment of the stability index revealed a prominent reduction in sedimentation and increased dispersion stability of the modified graphene solution as compared to the unmodified graphene. Furthermore, the modified graphene displayed prolonged settling rate that was much lower than unmodified electrochemically exfoliated graphene. These outcomes indicate that the Gum Arabic prominently improved the dispersion of graphene in water. Consequently, the Gum Arabic modified graphene boost the fluid loss control and decrease the fluid friction that conspicuously improve the overall efficiency of drilling fluids. The addition of the modified graphene to drilling fluid improved the dispersion stability, fluid loss control, and fluid friction that make it suitable for the diverse drilling applications.
Well Collision Risk Management by Fully Automated Wellbore Surveying
Authors: ElGizawy M. , Zackman N. , Hernandez J. , Gomez F. , Row A.
Published: February 2024

A survey program is designed for every well to meet the well objective of penetrating the target reservoir and avoid colliding with other offset wells. The selection of the wellbore survey tools within the survey program is limited in number and accuracy by the surveying technologies available in the industry currently. Quality Control QC measures are regularly in place to ensure the wellbore surveys’ accuracy is validated. However, wellbore surveys often delivered without conducting the full QC measures and sometime are delivered with failing QC measures. This increases the risk of missing the survey program's objective and more critical escalates the risk of the well collision with other wells.

Hence, quality control of survey correction is a key to the success of the overall objectives of the well construction. As automated survey-correction software is becoming commonplace among oil and gas operators it is important to consider its use in relation to the overall well risk management strategies. This paper is presenting the latest developed automation workflows to strictly guarantee the quality control and quality assurance of the wellbore survey while placing the well in real-time.

Automated Survey QC and correction platforms go a long way to reduce gross error or human related errors with algorithms and machine to machine data transfer protocols. Automated survey QC and correction platforms can be key components in robust risk management solutions for well construction. When implemented appropriately, they allow quick and automated quality check and corrections on wellbore trajectory position which is critical in Anti-Collision and tight target wells. Even though the correction platform is automated it still requires clarity and confidence in the algorithms. This can be achieved with features that are easily accessible, clear, and understandable to inexperienced users. In addition, there should be readily reachable domain experts who can confirm and further interpret the results quickly and clearly, especially when well objectives are in peril of not being met.

In this paper, automated survey QC and correction enablers are detailed. How quality control of survey correction are automated, strictly controlled and easily auditable. Additionally, case studies of well construction risk management are presented as well as the successful proof of eliminating human/gross error and non-compliance are demonstrated.

The wellbore position is calculated using wellbore surveys. The fact the surveys inherit errors due to tools and environment, the quality of surveys must be ensured and corrected in real-time. The presented technique automates the survey QC and correction process in real-time with a main objective to minimize the risk of colliding with another well or missing the production zone targets while being part of a robust risk management structure.
Seeing Beyond the Obscure Fluid: How an Enhanced Production Logging Approach Helped to Improve the Workover Design
Authors: Mirza W. H. , Khan M. T. , Saud R. , Espinoza I. B. , Farooq U.
Published: February 2024

Typically, well workovers are performed based on production logging results. However, efforts to shut down water-producing layers may result in the opposite effect, such as increased water cut and decreased oil production. Hydrocarbon inflow behind the stagnant water at the bottom of the well that cannot be measured by typical production logging tool (PLT) sensors and may cause interpretation errors. As no alternative tools are available on the market, an enhanced evaluation approach is required to interpret the hydrocarbon inflow behind standing water column.

Characterizing producing intervals in heterogeneous reservoirs with various saturation levels and low pay is difficult with only open-hole (OH) logs. A standard PLT approach based on spinners and density readings may not identify the oil and gas entry across stagnant water in vertical wells. Therefore, an enhanced procedure for PLT was developed. The flow behind the static or moving water column was first identified using a combination of pressure derivative (dP/dZ), temperature (dT/dZ), and density data. The zones with high dP/dZ fluctuations were used for potential hydrocarbon inflow. Secondly, the weighted average of the density trend was used to break down the potential hydrocarbon entry behind the water. The dT/dZ variation was input into the HC exact production. The OH results used for PLT correlation improved the final interpretation.

Two cases with multiple historical PLT were evaluated for this study. In Case 1 (Well x02), PLT was carried out three times over a four-year period, and the water cut increased following production based on the standard interpretation. Different workovers were attempted to shut off water inflows, both successful workover that led to a 27% increase in oil production and a 68% decrease in water production was possible after the improved interpretation of three-phase flow from the enhanced PLT approach. In Case-2 (Well x06), the new technique confirmed a masking behavior of water to the wellbore fluid flow, and the interval above was selected to guarantee the evaluation from the lower part. The study shows that the new approach to interpretation successfully quantified zonal contributions, helping to enhance the workover strategy and mitigate the increase in water cut level of up to 30%.

The improved PL interpretation workflow demonstrates that traditional PLT interpretation cannot be directly applied to reservoirs with three-phase flow and the objective of reducing water cut. The enhanced technique has good potential for successful interpretation and helped to reduce water production.
Comparison of Auto Y-Tool Versus Conventional Y-Tool for Improving Successful ESP Wellbore Access in H2S Oil Producer Wells
Authors: Dominguez F. E. , Flippin C. J. , Yateem K. S. , Banjar H. M.
Published: February 2024

The use of Y-tool assemblies permits production logging and stimulation work in Electric Submersible Pump (ESP) oil well completions. Auto Y-tools use a valve design which preclude the need for a blanking plug used in conventional Y-tool completions and hence provides an alternative to the use of standard Y-tool assemblies in oil well completions. This paper; therefore, compares the use of an auto Y-tool as an enhanced alternative to conventional Y-tool completions for successful wellbore access below an ESP.

To properly relate the operational requirements of conventional Y-tool during logging or stimulation activities, an Auto Y-tool design was identified and assessed based on its ability to automatically seal and unset above the bypass tubing depending on when ESP is in operation. An assessment of the compatibility of the metallurgy of the auto Y-tool components in an environment of high H2S partial pressure for the expected completion life was performed. Furthermore, an auto Y-tool installation would provide experience on its performance of the valve's benefit and its ability to seal and open as a means of enhancing natural flow production rate when the ESP is off.

The auto Y-tool assessment proved better, easier and more efficient to use in ESP well completion to the conventional Y-Tool system. The auto-Y-tool provides faster access to the wellbore below the ESP string than the conventional system for a typical well intervention. There is no need for additional wireline or slickline activities following the initial rig installation. This, in turn, reduces the amount of man power required during well intervention for an ESP well completed with auto-Y-tool. It further reduces the amount of time used in such intervention, which has direct impact on the operational cost and production costs per barrel. The absence of blanking plug in the auto-Y-Tool assembly reduces pressure loss caused by friction due to flow through the ESP stages, thereby increasing the production rate for a natural flowing well when the ESP in not in operation. This paper includes example calculations for natural flow in different flow paths in ESP completions

This paper offers operators a review of potential operational benefits of an auto Y-tool option to conventional Y-tool systems in ESP completion wellbore intervention.
A Data Driven Novel Perspective for Day-To-Day Digital Integrated Asset Operation Model and Business Intelligence Tool Utilization
Authors: Albadi Mohamed , Alsaeedi Ayesha , Alzeyoudi Mohamed , Alharethi Fahed , Alhammadi Maryam , Elabrashy Manar , Konkati Sarath
Published: February 2024

With increasing number of wells added over time in the matured fields to production sustainability, asset monitoring has become an integral part of the daily asset operation. Monitoring large number of wells as creates massive challenge related to increased man-hours spend and reduced efficiency due to manual work-process. This paper explains the data driven approach to overcome challenges monitoring for the asset operation utilizing the Integrated Asset Operation Model (IAOM) and Business Intelligence (BI) tools.

Prior to the implementation of IAOM and BI tool, conventional manual work-process was performed to achieve the asset monitoring. The data driven approach of IAOM links different corporate data sources under a single centralized digital platform. This platform utilizes historical, real time and model-based data for further analysis, visualization, and monitoring purposes. IAOM utilizes a combination of data to run the complex engineering algorithm and presents analytical output to the users in the form of trends, grid, and statistical screen. The smart user defined BI dashboard and reports is integrated with the IAOM platform thus creating a single digital framework for asset monitoring.

The key drawbacks of the conventional manual steps are the increasing man-hours on data gathering and data validation. Thus, resulting in less time on analysis and delaying bottleneck detection. After the implementation of data driven approach as part of IAOM, the increase man-hours diverted on analysis instead of data gathering and validation. The utilization of complex engineering algorithms and automated workflows have significantly reduced time consumption on asset monitoring and debottlenecking. The linkage of different data sources has enabled creating a single source of record (Sor) across the entire asset. This has also improved the efficiency and accuracy of the analytical studies. The intuitive plotting and trends functionality of the data or combination of data helps in comparative analysis over time or related well parameters. Integration of advanced BI tool within the IAOM has enabled creation of smart and intuitive dashboards and reports which cater to the needs of different job roles within the asset. Thus, the end user gets a bird eye view on the information relevant for his day-to-day asset monitoring task.

As a part of IAOM, standard Thirteen workflows and work-process were implemented with an ability to consume large and varied data set from different sources for more accurate and efficient outcomes with respect to the conventional approach. This approach is an integration of data driven analysis, user expertise and advanced technology capitalization.
Hydrocarbon Value Enhancement: A Novel Total Systems Solutions Approach for Contaminants Removal
Authors: Pinappu S. R. , Murugesan S. , Jani J. K.
Published: February 2024

A unique solution has been developed to tackle the problems caused by contaminants that can adversely affect the quality of hydrocarbons. These contaminants can lead to issues such as corrosion, fouling, and concerns related to health, safety, and the environment. The approach involves using a combination of specialized chemical additives and mechanical equipment to improve the quality of the hydrocarbon stream and increase its market value. This holistic approach ensures a synergistic effect, resulting in a premium quality hydrocarbon product.

The marketplace typically regulates the quality standards of hydrocarbons through organizations such as ASTM and ISO. These standards are determined by measuring the levels of contaminants present using approved testing methods. There are several contaminants that are commonly tested for, including but not limited to mercury, arsenic, iron, aluminum, silica, and sulfur. These contaminants present significant challenges in processing and can also pose health, safety, and environmental risks. Although traditional chemical additive treatment can assist in bringing the hydrocarbon stream back to its desired specification, these methods are often time-consuming and not always effective in completely removing certain contaminants. This paper proposes a new system solution approach that includes ideation, pilot plant studies, and final long-term implementation. The approach involves the use of contaminant-selective chemical additives and appropriate mechanical separation equipment.

This paper demonstrates practical examples of eliminating contaminants from various hydrocarbons through a total systems approach. The contaminants in question, including mercury, arsenic, iron, aluminum and silica, were effectively removed using chemical additives like carbonamide/thiocarbamide, acid-catalyzed resins, and sodium tetra hydroborate. To achieve optimal results, we also utilized separation equipment such as centrifuges, decanters, and liquid-liquid contactors. This innovative system utilizes a selective chemistry approach combined with mechanical equipment to enhance the value of hydrocarbons through a synergistic effect. Furthermore, the study proposes the possibility of utilizing this approach in the realm of sustainable energy sources.
Utilization of Innovative Elastomeric Cement Integrity Sleeve as A Field Proven Cement Assurance Solution: A Sustained Annular Pressure Prevention Case Study
Authors: Osorio A. , Vliegenthart A.
Published: February 2024

Well integrity maintenance is one of the most prominent concerns encountered throughout the life cycle of an oil & gas well. Operating companies and governmental regulatory bodies increasingly place significant emphasis on well-construction optimization, safety risk mitigation, and environmental sustainability as an effort to prevent well integrity issues while simultaneously maximizing operational longevity and commercial profitability. While many factors have a direct impact on well integrity, significant importance is placed on cement assurance and relevant optimization techniques given the intrinsic nature of cement as the main physical barrier preventing upwards annular gas migration and subsequent sustained casing pressure build up on surface. Moreover, the oil & gas industry places considerable emphasis on optimizing cement assurance by preventing typical cement failure mechanisms such as chemical shrinkage and casing-to-cement bond failure which commonly occurs as a direct result of cyclic pressurization and tubular ballooning occurrences during mechanical integrity testing and hydraulic fracturing operations.

An innovative and unique elastomeric cement integrity annular sleeve has been developed with the objective of cement assurance optimization and annular gas migration prevention. Distinctly different in comparison to a conventional swellable packer, the elastomeric cement integrity sleeve is a thin elastic swelling seal designed for onsite slip-on installation externally onto oilfield tubulars; it is a high-value solution capable of swelling and establishing an effective casing-to-cement seal in the event of micro-annular flow path emergence throughout cemented casing and tubing sections.

The elastomeric cement integrity sleeve can be installed onto all oilfield tubular sizes ranging from 2-7/8" tubing to 30" conductor casing and does not require additional downhole components, moving parts, or operational actuation for its activation. It is designed to swell and seal a micro-annular flow path immediately upon direct exposure to wellbore fluids after cement displacement. By preventing gas migration in critical barriers, the technology provides increased value given significant CAPEX & OPEX savings as a result of elimination of remedial cementing requirements and operational simplification during plug and abandonment decommissioning activities.

This publication presents a detailed explanation of the technology, it showcases the simplicity of its onsite installation sequence and provides an overview of global installations to date. Furthermore, it provides an overview of a recent case study carried out in conjunction with a major global oil & gas operating company in which utilization of the elastomeric cement integrity sleeve resulted in an 80% reduction of sustained annular gas pressure in a multi-well drilling campaign in the Far East.
High Bandwidth Distributed Acoustic Sensing for Microcrack Detection
Authors: Turolla A. , Zampato M. , Correra S. , Schenato L. , Palmieri L.
Published: February 2024

This paper presents a new system for distributed acoustic sensing (DAS, Hartog 2018 [3]). This system can continuously monitor structures along paths with a total length of several kilometers. It can detect fast impulsive events, such as those generated by microcracks, that can have a duration of around 1 μs. This is particularly useful for monitoring structures susceptible to microcrack phenomena, where traditional DAS systems may not be able to detect such short vibration events. This new system has many potential applications in predictive maintenance, including monitoring long structures like pipelines, tubulars for oil and gas wells, and wind turbine blades.

The system relies on a novel Continuous Wave probing of the sensing fiber based on Orthogonal Frequency Division Multiplexing (OFDM, Schulze, Lueders 2005[3]), which is commonly used in digital television, DSL internet access, wireless and mobile communications. OFDM is used to continuously probe the sensing fiber and overcome the limitations imposed by the round-trip propagation time of the probe pulse in traditional DAS systems. With this method, the acoustic sampling rate can be increased beyond the traditional limit. This results in higher sensor bandwidth and greater efficiency in the system.

Here, a theoretical model of the system is developed to define the hardware of the interrogator, formulate the algorithm for extracting the vibration signal from the optical signal, and evaluate the theoretical system performances. Subsequently, a lab-scale system prototype is designed and built to validate the soundness of the technique.
Understanding Field-Scale Hydrogen Storage Performance in Saline Aquifer Using Experimentally Measured History-Dependent Saturation Function and Numerical Simulation
Authors: Omeke J. , Siddharth M. , Retnanto A.
Published: February 2024

Surpassing natural gas in energy density, underground hydrogen storage (UHS) and its subsequent utilization offer a pivotal advancement in large-scale energy strategies, countering renewable energy fluctuations and reducing anthropogenic emissions. Like other storage systems, UHS is still in its infancy, with limited experiments characterizing the multiphase flow of hydrogen in aquifers. These flows are described using saturation functions (curves in reservoir simulation representing the relationship between relative permeability and capillary pressure). Given the periodic injection and production of hydrogen, saturation functions don't rely solely on current saturation; they also consider the path or history the saturation has taken, facilitating transitions between drainage and imbibition also known as hysteresis. Recent publications underscore the significant influence of hysteresis on recovery factors, and neglecting these effects can introduce substantial uncertainties in cumulative hydrogen recovery.

While many UHS simulations have used individual saturation functions (With or without hysteresis), results vary depending on the experimental curve selected. In this study, we take a more holistic approach. We've combined the four most recent and improved hysteresis-based saturation function measured directly from hydrogen-brine experiments. Simulating under specific reservoir conditions, we are assessing how these combined curves influence hydrogen storage and recovery. To provide a tangible perspective on potential field-scale effects, we demonstrated our findings using a simulation based on actual field data. Through this method, we aim to offer a more cohesive insight into recovery outcomes across these different experiments.

In this study, when applying various experimental curves to the reservoir model, a mere 9% difference in recovery was observed. This indicates a relatively minimal variability in recovery outcomes across different saturation function experiments and injection-production schemes. Moreover, overlooking hysteresis might result in recovery overestimations ranging from 3% to 16%.
Use of Ranking and Clustering Analysis for Robust Well Placement and Efficient Reservoir Sweep
Authors: Al-Ismael M. A. , Abouheit F. F. , BuKhamseen N. Y.
Published: February 2024

With the advancement in technology and the growing availability of data sources, the size of data in the oil and gas industry is increasing at an exponential rate. While large subsurface datasets present more opportunities for field development planning, they also present some challenges in data mining and analysis. This work presents methodologies that can help unlocking the potential of reservoir models to drive insightful field development planning activities more efficiently. A simulation model of a synthetic heterogeneous reservoir is used in this work to evaluate reservoir opportunities for placing new wells. A 3D map of an opportunity index is first prepared using dynamic reservoir properties. Ten clustering analysis methods are then used to group the 3D map grid cells into different target regions. The generated regions are ranked based on their average reservoir opportunity index and hydrocarbon volumes. Ten new wells are then designed and placed in the highly ranked regions and then evaluated using numerical simulation. Results from the ten clustering methods are compared. Each clustering method resulted in a unique set of regions and hence, different locations and designs of wells. The comparison is performed by measuring the overall performance using cumulative oil production as well as by analyzing the clustering quality using silhouette score. The regional-based ranking resulted in an improved reservoir sweep. However, it may not be the optimal due to rig scheduling constraints since the selected regions are scattered. The analysis shows the impact of tuning the hyperparameters of the clustering methods and their significance on generating optimum target regions. This work highlights potential opportunities to improve the sweep efficiency in hydrocarbon reservoirs by capitalizing on data analysis techniques that complement conventional metrics and methodologies. It demonstrates an integration between clustering analysis and reservoir opportunity workflows which can lead to optimum field development planning.
Experimental Study on Stuck Pipe Release by BHA Whirling
Authors: Machocki K. , Aljohar A. , Nazzari I. , Vaziri V. , Wiercigroch M.
Published: February 2024

Differential pressure sticking (DPS) is one of the most common causes of pipe sticking when a drill-string rests on a borehole wall or even is submerged into a mud cake [1]. Differential sticking can significantly impact the cost of wells and non-productive time for the rig and usually harms the environment, particularly if the BHA has to be abandoned downhole. Failure to free a drill-string leads to significant financial losses due to contractual charges, time-consuming interventions, hole abandonment, side track requirements, environmental problems and others. The existing technology can apply only a limited axial force and jarring load to the stuck object. Thus, a new method should be developed and employed to release differentially stuck pipe problems.

To overcome DPS, a concept of the "Advanced Shock Tool" was proposed by Saudi Aramco in the patent US2019368295 [2]. The idea of this tool stems from generating periodic or chaotic lateral loads on the stuck point rather than applying conventional methods, subjecting the stuck point to axial impact loading only. The expectation is to generate these additional forces by applying torque on the asymmetric pipe section above the stuck point, with under-gauged stabilisers and a rotary tool disconnecting torque transmission from the stuck point.

To address the above-discussed challenge of a differentially stuck pipe, a large-scale experimental rig was designed, manufactured, installed and instrumented to investigate the whirling motion of a shaft interacting with housing to mimic the new jarring method introduced earlier. This experimental study focuses on generating large lateral vibration by developing a robust backward whirling motion, examining the possibility of generating and sustaining such dynamical responses for a wide range of parameters, and ultimately proving the concept of the Advanced Shock Tool in a large-scale experimental setup. The following sections describe the developed experimental setup, experimental strategy and the main results.
New Technology Enables Effective Geosteering Optimization in Low Resistivity Pay – Case Study from Offshore China
Authors: Yang Yong , Hu Wenli , Feng Jin , Xie Xiong , Wang Haifeng , Wang Fei , Wang Chao , Chang Botao , Li Tong
Published: February 2024

Field X in offshore China has a target reservoir with characteristic of low resistivity and low permeability. Resistivity of the target zone is as low as 1 Ohm.m to 3 Ohm.m, while the surrounding calcareous interbeds have only slightly elevated resistivity of 2 to 5 Ohm.m. Besides this, the thickness of the target zone can be as thin as 1 m. Conventional resistivity based geosteering tool usually could not map these boundaries clearly, which often resulted in poor geosteering performance and sometimes sidetracks.

A new directional resistivity tool with new sensor and newly invented measurements, along with a novel inversion process, brings hope to tackling the geosteering challenges in this type of environment. In addition to the axial and titled antennas that were already in the conventional tool, this new tool has introduced a transverse antenna that could better measure formation anisotropy and hence help delineating thin layers. A new family of deep resistivity measurements are also added to increase the detection range of the tool and the mapping capability for low resistivity environment. Finally, a new multi-layer deterministic parametric inversion method is designed and can take full advantage of the new measurements, to achieve higher resolution and larger depth of detection at the same time.

The new tool was utilized in a recent infill campaign for the field X to place horizontal sections in this low resistivity payzone. With the improved mapping capability of the tool, the operator was able to geosteer within the thin and low resistivity target zone with high net-to-gross (NTG) and success rate. In one of the examples illustrated in this paper, the target zone was only 1.3m thick, with calcareous interbed above and below. The resistivity contrast was very limited, with resistivity of the target zone and the calcareous interbed less than 2 Ohm.m and 4 Ohm.m respectively. Under this very challenging environment, the operator achieved 861 m horizontal section with 100% NTG. The calcareous interbed below was mapped clearly which enabled the operator to make informed geosteering decisions to maximize reservoir exposure for horizontal sections.

This new technology opened the door for developing the low resistivity pay in this field effectively. With the enhanced remote mapping capability, the operator now is able to drill longer horizontal sections with better NTG which ultimately helps achieve increased production.
Preventing Drill String Twist Offs Due to HFTO coupled with High Stick-Slip RPM for RSS BHAs
Authors: Singh Varun
Published: February 2024

All drilling dysfunctions or vibrations including High Frequency Torsional Oscillation (HFTO) are monitored in real time with current technology of Drilling Bottom Hole Assembly (BHA). There are certain limits set for each kind of vibration and drilling parameters are optimized while drilling to overcome these dysfunctions. The main objective of this paper is to present a detailed case study of showing the impact of HFTO within the permissible limits which can be monitored in real time, combined with lower to moderate levels of stick slip leading to twisting off Rotary Steerable System (RSS) drilling BHAs. This paper covers the implementation of a new strategy to eliminate twisting off BHAs due to HFTO thereby avoiding Non-Productive Time (NPT) and any additional costs that could be incurred due to an incident such as fishing, unplanned sidetracks etc.

Drilling with PDC bits across Anhydrites always generates HFTO. However, frequency and amplitude of HFTO depends on the type of Bit, rock strength, BHA configuration and drilling parameters. Historically, in the majority of BHA twist off incidents, real time vibrations and drilling parameters are within the maximum allowable tool limits. Monitoring HFTO in real time (RT) is limited due to high sampling rate of vibration data which cannot be transmitted in real time. With the advancement of technology in RSS all high frequency vibration data is stored while drilling and can be analyzed after the run. Memory analysis along with HFTO modelling were carried out for multiple runs to evaluate the impact of torsional loads. Detailed analysis of this high frequency memory, formation behavior, drilling parameters and bit features was done to compare between good and failed runs. Based on the analysis, new guidelines and corrective actions were implemented to eliminate BHA twist offs.

Based on the memory analysis and modeling, torsional loads were higher during stick slip events exceeding tool's limits leading to twist off and it was found to be common in all twist off incidents. New corrective actions were implemented on subsequent runs that resulted in avoiding twist offs by 100%. This translated to reduced trips for failure, tool maintenance cost and improved overall efficiency. In certain applications, depending on the above-mentioned factors HFTO will trigger, however with an optimized well program, drill string twist-off can be avoided.

The methods and processes presented in this paper can be applied globally in the areas with similar challenges. This would result in delivering the wells in the most efficient way by reducing lost time and improving efficiency.