bluuebunny/crossref_metadata_2025 huggingface dataset:
Advanced Light Weight Thixotropic Lost Circulation Cement Solution for Vugular and Natural Fractured Limestone Formations: UAE Offshore Case History
Authors: Doutoum Mahamat Habib Abdelkerim , Bermudez Alvarado Romulo Francisco , Alaleeli Ahmed Rashed , Phyoe Thein Zaw , Salazar Jose , Albuja Eduardo Herrera , Kapoor Saurabh , Orfali Mohd Waheed , Rahhal Gilbert
Published: December 2021

Lost circulation while drilling across vugular or naturally fractured limestone formations is a costly challenge and has financial impacts including nonproductive time and remedial operational expenses. Many fields in the UAE are encountering notorious lost circulation complications, which are difficult to control with conventional lost circulation solutions while drilling surface sections. Novel lightweight thixotropic cement has proven beneficial to take control of severe losses in these vugular and naturally fractured limestone formations.

The main challenge while drilling across the surface section in UAE offshore field is the heavy or total loss of returns. Drilling performance is affected due to poor hole cleaning, a risk of stuck pipe, surface fluid handling problems, and well control risks. Conventional extended cement slurries have been widely used to cure losses while drilling but with limited success. A new lost circulation solution combines lightweight (10.5- lbm/galUS) high solids fraction cement (trimodal system) and a thixotropic agent, which develop fast gels with high compressive strength. Thus, it enables plugging of large voids and fractures to deliver the wellbore integrity required to continue drilling with enhanced performance and efficiency.

Intensive laboratory qualification tests focusing on static gel strength and compressive strength development was performed to tailor the new solution. The results were promising with more than 100 lbf/100 ft2 of static gel strength in 10 minutes and compressive strength development of 1,000 psi within 24 hours at low surface temperature. In addition, a transition time (TT) on-off-on test demonstrated more rapid gel strength development when the shear is reduced and regained fluidity with reapplication of shear.

In one of the wells, heavy losses were encountered while drilling across surface section. The lightweight thixotropic solution was pumped for the first time worldwide and it was shown that the innovative lost circulation solution was effective in significantly reducing the losses and enabled the operator to continue drilling to section TD.

This case study demonstrates that this advanced system is effective in curing losses and reducing nonproductive time. The unique properties of faster rapid gel strength and high compressive strength make this solution effective for treating a wide range of lost circulation events while drilling. Furthermore, the advanced lightweight thixotropic cement lost circulation solution exhibits strong performance in curing heavy losses and establishing well integrity with reliability.
Experimental Results to Design Lactic Acid for Carbonate Acidizing
Authors: Alhamad Luai , Alfakher Basil , Alrustum Abdullah , Aldarweesh Sajjad
Published: December 2021

Acidizing deep carbonate formations by Hydrochloric acid (HCl) is a complex task due to high reaction and corrosion rates. Mixing organic acids with HCl is a typical method to reduce the acid's reactivity and corrosivity. Lactic acid has not been investigated completely in the area of carbonate acidizing. Lactic acid has a dissociation constant similar to formic acid, which is approximately 10 times larger than acetic acid. Therefore, the objective of this work is to compare lactic/HCl blends with plain HCl and formic/HCl blends.

Corrosion tests were conducted at high temperature on C-95 steel coupons to investigate associated corrosion damage. Coreflood tests were performed on Indiana limestone cores to mimic matrix acidizing treatment and to investigate amount of pore volumes required to breakthrough. All blends were prepared to be equivalent to 15 wt% (4.4 M) HCl for comparison. Lactic and formic acid concentrations were set to be (0.5 or 1 M), and HCl concentration was calculated as appropriate to reach a blend with strength of 4.4 M.

In terms of corrosivity evaluation, blends of lactic and HCl acids showed a corrosion rate of up to 1.97 lb/ft2 at 300°F. The formic and HCl blend showed a corrosion rate of 1.68 lb/ft2 at the same temperature. The difference in corrosion rates between the two mixtures is due to molecular weight difference between lactic and formic acids. When both acids were prepared at 1 M, lactic acid blend required more HCl to be equivalent to 15 wt% HCl acid which was associated with an increase in corrosion rate. Coreflood results established acid efficiency curves for lactic/HCl acid blends. The curves highlighted the correlation between acid-core reactivity, injection rate, and dissolution pattern. Lactic/HCl blend was less reactive than formic/HCl mixture as the last required lower injection rate to obtain optimum pore volume to breakthrough at 300°F. Lactic/HCl blend was able to generate an optimum dissolution pattern as a dominant wormhole was shown on tested core plugs inlet face.

This study expands the investigation of lactic acid utilization in carbonate acidizing. Major advantages rendered by using lactic acid with HCl include: (1) favorable dissolution pattern due to lactic acid being less reactive than HCl or formic acids, and (2) less corrosion rates comparing to HCl, that can reduce allocated costs for maintenance and replacements.
Application of Okra Mucilage for the Prevention of Shale Swelling
Authors: Murtaza Mobeen , Tariq Zeeshan , Kamal Muhammad Shahzad , Mahmoud Muhammad , Al Sheri Dhafer
Published: December 2021

Maintain wellbore stability is a very critical aspect of the drilling operation. The unstable wellbore provides severe loss to the drilling operators in terms of time and money. One of the significant reasons for unstable wellbore occurs due to the expansion of shale formation. Several solutions are utilized to tackle the expansion of shales, such as salts, PHPA, silicates, and oil-based drilling fluids. There are limitations associated with these solutions, such as thermal instability, limited supply, unfriendly to the environment and marine life, etc. In this study, Okra mucilage has been introduced as a shale swelling inhibitor in drilling fluids. Okra is widely used in the medical and food industries as a viscosifier as it is abundantly available in tropical and subtropical regions. Okra powder has been used as a fluid loss control additive in the literature. The application of the Okra solution as a shale swelling inhibitor in drilling fluids was not investigated in the past.

In this study, Okra mucilage was extracted from the Okra plant and used as shale swelling inhibitor. Three different concentrations (5, 10 & 20) vol% of Okra mucilage mixed solutions were used for linear swell test. The test was performed using a linear swell tester at atmospheric conditions for 24 hours on bentonite wafers. Further zeta potential, particles size and capillary suction timer test (CST) were conducted. The experimental study revealed that Okra mucilage reduced the swelling of bentonite. For instance, 10 and 20% of Okra mucilage solutions reduced the swelling by 36.8% and 50.5%, respectively. The Okra mucilage decreased the zeta potential of clay and increased its particle size. CST time decreased initial at low concentration and increased with concentration. Overall, experimental investigations suggested that Okra mucilage could be an alternate green shale inhibitor in drilling fluids without compromising other drilling fluids' properties.
The Role of Turbomachinery in Enabling the Hydrogen Economy
Authors: Corbò Simone , Wolfler Tommaso , Banchi Nicola , Furgiuele Ippolito , Farooq Majid
Published: December 2021

The purpose of this paper is to present the various technological solutions optimized for the use of hydrogen, in transport, distribution, storage and utilization, analyzing their criticalities and advantages. Hydrogen compression is a fundamental step in the transportation and storage segments and continuous improvement are required. The greatest technological challenges are certainly the high pressures required for the various fields of use, the need to maintain a clean gas and to use materials that are not subject to embrittlement. The choice between the different compression technologies is based on the need for pressures and flow rates; in the case of high flow rates and low compression ratios a centrifugal compressor is preferable, while for low flow rates and high compression ratios the choice goes to piston compressors.

To prevent gas contamination, dry reciprocating compressor are preferred because they allow to avoid an oil separator filter on the discharge. Current technology of reciprocating compressors allows to compress hydrogen up to 300 bar with lubricated machines, while with dry technology it is possible to reach up to 250 bar. A second criticality on reciprocating compressors is maintenance: the parts subject to wear need to be serviced every 8000 hour of operation. The use of innovative materials will increase the maintenance intervals reaching higher pressures without lubrication.

To increase the pressure ratio with centrifugal compressor, it's needed to increase the rotating speed, therefore the peripheral speed, with materials suitable for H2, stages get high compression to reduce the number of compressor bodies.

If the process conditions require high delivery pressures combined with large flow rates, a solution of centrifugal compressors alone would be able to manage the flow rate but not the required delivery pressure. On the other hand, the use of reciprocating compressors would require a considerable number of units. In this case, therefore, the optimal solution is to combine the two technologies, centrifugal and pistons, using the best features.

A case study in which the superior performances of the hybrid solution in terms of total cost of ownership will be described and compared with traditional single technology compression train
Probabilistic Economical Evaluation for Business Decisions Through Integrated Uncertainty Assessment and Reliable Ensemble-Based Production Forecasts
Authors: Abd-Allah Mohammed , Abdelrahman Ahmed , Van Den Brul Luke , Taha Taha , Javed Mohammad Ali
Published: December 2021

Economic evaluation of exploration and production projects ensures a positive return for asset operators and stakeholders and evaluates risk in field development decisions related to both reservoir model uncertainties and fluctuations in oil and gas prices. Traditionally, such evaluation is performed manually and deterministically using single or limited number of cases (limited number of reservoir models and few values of economic parameters). Such traditional approach does not integrate seismic-to-simulation reservoir model uncertainties, the reservoir model used is often unreliable due to inconsistent property modifications during the history matching process, full span of prediction uncertainty isn't properly propagated for economic evaluation and the whole process is not fully automated.

This paper presents an integrated and automated forward modelling approach where static and dynamic models are connected to integrate the impact of uncertainties at the different modelling stages (seismic interpretation through geological modelling to dynamic simulation and further to economic evaluations). The approach is demonstrated using synthetic 3D model data mimicking a real North Sea field. It starts by building an integrated modelling workflow that can capture the various reservoir model uncertainties at different stages to automatically generate multiple probable model realisations. Proxy models are constructed and used to refine the history match in successive batches. For each prediction development scenario, prediction probabilities are estimated using posterior ensemble of geologically consistent runs that matches historical observed data. The ensemble of reservoir models is automatically evaluated against different possible economic scenarios.

The approach presents a seamless and innovative workflow that benefits from new-generation hardware and software, enables faster simultaneous realisations, produces consistent and more reliable reservoir models. Probabilistic economic evaluation concept is implemented to calculate the statistical probabilities of economic indicators.
Using New Intervention-less Surveillance Technology to Optimize the Implementation of Waterflood
Authors: Al Anbari Ali , Al Harthi Mahmood , Choudhury Suryyendu , Borkent Evert-Jan , In ‘T Panhuis Petrus , Hemink Gijs , Al Yahmadi Mundhr , Abdul Abbas Hawra , Morianta Marpaung
Published: December 2021

The value of implementing intervention-less downhole surveillance technology lies in early assessment of field-scale reservoir performance and well deliverability in South Oman's largest waterflood development. Such technology can aid in assessing whether aquifer support by means of (controlled) fracture injection is achievable, which is potentially more valuable than matrix injection to enhance oil production. At the same time HSSE exposure and deferment will be reduced by avoiding well interventions. This paper will share learnings from Distributed Fiber-Optic (FO) Sensing technology.

More specifically, this paper will present the case study of field ‘A’, where waterflood is being operated in two methods based on sectors depending on field geological and reservoir properties:

‘Deep’ water injection in the aquifer, under fracture conditions ‘Shallow’ water injection close to the oil-water-contact (OWC), under matrix conditions

‘Deep’ water injection minimizes the risk of early water breakthrough, but it delays the aquifer pressure support which in turn means lower offtake. The ‘Shallow’ water injection (trialed by injecting water 50m below OWC) has a higher risk of water short circuiting, accelerates pressure support and thereby enhances production / well deliverability.

Fiber-optic data is part of a decision-based surveillance program, which also included injection / production logging via PLT, step-rate tests, and pressure monitoring. The time-lapse data has illustrated some fracture growth up- and downwards of the perforation interval in most wells but is still contained below the OWC. In some wells, the injection growth is also controlled by the presence of several intra-reservoir shale baffles that are acting as barriers to vertical communication and thereby delaying the injection response while inducing a strong pressure response in nearby producers. The data has helped to further calibrate and validate the model assumptions and will help in optimizing the waterflood development concept for the field. Proactive interventional-less surveillance enables monitoring of the zonal injection conformance, provides advantage of learning reservoir performance and supports agile WRFM operations and decision making. Furthermore, cost competitive and credible technology have made PDO a front runner to keep subsurface risk at as low as reasonably practical levels and boost oil production. This distributed fiber optic sensing technology provided cost-effective, fit-for-purpose, and intervention-less well-and-reservoir surveillance.
Enhanced Production with Self-Driven Multi-Phase Pumps
Authors: Abdul Halim Maamoun , Maianti Emiliano
Published: December 2021

Some wells are either producing intermittently or ceasing against the trunk line pressure due to low flowing wellhead pressure. OLS with MPP provides the flexibility such as boosting pressure from low flowing wellhead pressure well to the existing trunk lines. The MPP has a wider pressure operating envelope to accommodate the less flowing wellhead pressure well in long run. Incremental Oil & gas production will be realized by lowering the FWHP on this well using the OLS.

Multi-Phase Pumps solutions have sustained production from marginal and restarted non-producing wells.

Production gains are highly dependent on the reservoir and well parameters.
Using AI/ML to Explore & Develop Quickly and Efficiently
Authors: Aming Anthony
Published: December 2021

See how application of a fully trained Artificial Intelligence (AI) / Machine Learning (ML) technology applied to 3D seismic data volumes delivers an unbiased data driven assessment of entire volumes or corporate seismic data libraries quickly. Whether the analysis is undertaken using onsite hardware or a cloud based mega cluster, this automated approach provides unparalleled insights for the interpretation and prospectivity analysis of any dataset.

The Artificial Intelligence (AI) / Machine Learning (ML) technology uses unsupervised genetics algorithms to create families of waveforms, called GeoPopulations, that are used to derive Amplitude, Structure (time or depth depending on the input 3D seismic volume) and the new seismic Fitness attribute. We will show how Fitness is used to interpret paleo geomorphology and facies maps for every peak, trough and zero crossing of the 3D seismic volume. Using the Structure, Amplitude and Fitness attribute maps created for every peak, trough and zero crossing the Exploration and Production (E&P) team can evaluate and mitigate Geological and Geophysical (G&G) risks and uncertainty associated with their petroleum systems quickly using the entire 3D seismic data volume.
Digital Transformation Journey of Field Operations at Abu Dhabi Offshore Field in UAE
Authors: Ahmed Talha Rafi , Januel Bastien , Fuenmayor Morealvin
Published: December 2021

Field operations generate large volumes of data from various equipment and associated Meta data such as inspection due dates, maintenance schedule, people on board, etc. The data is often stored in silos with a data guardian for each entity. The objective of this project was to volarize the data by developing engineered KPI's to drive decision making and make data accessible for everyone in the organization to foster cross collaboration.

Data analytics and visualization solutions were developed to automate low value-added tasks either using robotic process automation scripts or business intelligence reporting tool. Data was residing either in spreadsheet or native applications. With support of IT, centralized database was established. Scrum agile project management techniques were used to develop digital solutions. A high-level digital road map was created consulting all teams including stake holders. Use cases were identified and captured in lean A3 problem solving format. Each use case clearly identified the benefits to organization, and this was used to prioritize the use cases. A sprint was set-up with agile team and products were developed as per end user's expectation. The constant feedback loop via daily stand-up meetings helped the team deliver value added products.

Digital solutions were developed to automate low value-added tasks so employees can focus on improving systems instead of producing reports. By developing engineering KPI's and predictive analytics, technical authority could shift from reactive maintenance to pro-active maintenance. Using linear regression machine learning, early warning digital solution was developed to monitor and notify technical authority to clean strainers. The production team achieved 0.75 full time equivalent (FTE) in time savings by automating reports. By visualizing operations data such as flaring, production profiles; the team minimized flaring leading to 1% OPEX cost saving. Around 10% of chemical budget was saved by monitoring chemical injections at all platforms. Similar cost savings were achieved by visualizing data for other disciplines such as maintenance and HSE teams. By being better informed about wells annuli pressure build-up via email notifications, wells integrity team reduced the associated risk. By forming a multi-disciplinary agile team with business and delivery team, digital team deployed 20+ digital products over a short time frame of 2 years.
Instrument Safety Valves Enhanced Maintenance Strategy
Authors: Al Naumani Yahya Hamood , Al Abri Abdul Aziz Ahmed , Al Ruqaishi Mahmood Ahmed
Published: December 2021

Emergency Shutdown (ESD) and Blowdown (BDV) valves are the final elements part of the Safety Instrumented Functions (SIF) in which are deployed in oil and gas assets. They are classified as safety critical equipment to prevent major accident hazards. The conventional method of proof testing these valves is to close/open them fully, and thus require a process shutdown. In general, planned process shutdown is only viable every two to four years. Such infrequent and limited tests lead to imperfect testing and degrade the reliability of safety instrumented functions. Accordingly, this paper presents the work done to develop a comprehensive maintenance strategy that addresses lifecycle management of safety instrumented function in operate phase which help reduce the potential of process safety incidents. In summary, the innovative approach presented by this paper offers best practice of safety critical system integrity management implementation to achieve the highest standards of operational excellence.
Three-Dimensional Visualization of Oil Displacement by Foam in Porous Media
Authors: Wong Josiah Siew Kai , Suekane Tetsuya
Published: December 2021

Foam Enhanced Oil Recovery (EOR) has been employed as an improved recovery method due to its best sweep efficiency and best mobility control over the other injection method such as gas flooding, water flooding and other EOR methods. Foam which has high viscosity illustrates great potential for displacing liquid. The relative immobility of foam in porous media seems to be able to suppress the formation of fingers during oil displacement leading a more stable displacement. However, there are still various parameters that may influence the efficiency of foam assisted oil displacement such as oil properties, permeability of reservoir rock, physical and chemical properties of foam, and other parameters. Also, the interaction and displacement patterns of foam inside the porous media are remained unknown. Thus, in this study, we investigated the three-dimensional (3D) characteristics of oil recovery with gases, water, surfactant, and foam injection in a porous media set-up. By using CT scanning machine, the fluid displacement patterns were captured and analyzed. Moreover, the effect of oil viscosity on foam displacement patterns is studied. The study provides a qualitative and quantitative experimental visualization of 3D displacement structure, oil recovery with gases, liquid and foam injection. As a result, the comparison of fluid displacement patterns between gases, water, surfactant and foam injection show that foam has the good ability in sweeping and forms stable displacement front. The combination of surfactant, liquid and gas, which makes up foam resulted in a synergistic effect in oil displacement. On the other hand, viscous fingering, gravity segregation, trapped oil phenomena are shown in gas flooding and liquid flooding experiments. Thus, foam which displaced stably across the permeable bed resulted in the highest oil recovery factor. The mechanism of foam flow in porous media was understood in this study. Foam, as a series of bubble, burst and become free moving liquid and gas particles when in contact with oil and porous media. Therefore, two displacement fronts could be found from the foam injection experiment, in which the front layer moving ahead in contacting with oil bank is the discontinuous gas/liquid layer and followed by stably foam bank at the back. Due to the stable displacement of foam bank, the effect of oil viscosity on foam displacement is suppressed and showed no distinction in terms of displacement patterns. The flow regimes are found to be the same despite different viscosity of displaced oil. There has been no linear correlation proved between the oil viscosity and oil recovery factor.
Drilling in the Digital Age: Sensors in Bit and Underreamer Improves Future BHA Design Offshore Mexico
Authors: Batruny Peter , Aburto Zuriel , Slagel Pete , Paimin M Razali , Mahran Mohamad , Cortina Carlos Jose
Published: December 2021

Downhole vibration is the primary cause of low Rate of Penetration (ROP), and severe vibration causes Bottom Hole Assembly (BHA) tool failure; it is especially apparent during Hole Enlargement While Drilling (HEWD) due to multiple points of cutter contact with the formation at the bit and the underreamer. Electronic, high data rate sensors, embedded in the 17-1/2 in. bit and the 22 in. underreamer, generated detailed insights on the location, mechanism, and magnitude of downhole vibration.

Time-based downhole vibration logs from the sensors were plotted alongside mudlogging data. Finite Element Analysis (FEA) models were run using actual drilling parameters to simulate downhole conditions and provide a baseline model for further optimization. Sensor data was isolated for each of the bit and underreamer to better understand the individual and combined vibration mechanisms during hole enlargement while drilling operations. The FEA model was then used to optimize BHA configuration and underreamer placement that result in the largest drilling parameter window for future BHAs.

The data from sensors showed that whirl occurred when the bit entered sandstone bodies and the underreamer was still in shale. The data also showed that when the bit was in shale and the underreamer in sandstone, the underreamer experienced stick slip which induced stick slip at the bit. The BHA dynamics model run with actual drilling parameters showed a narrow drilling window with multiple critical vibration points at the same rotation speed (RPM). A new BHA was developed for the next well with a wider drilling window and less critical vibration points for the same RPM. The analysis identified key operational mitigations when stick slip or whirl are encountered.

This work leveraged technology and insights generated from data to shorten the learning curve and improve operations after just one well. In a drilling age where operations are becoming increasingly complex, relying on surface data is no longer enough.
Rationalization of Flares at Terminal Island
Authors: Akhtar Tehsin , Maiti Bablu Kumar
Published: December 2021

This study aims to assess potential opportunities for optimizing the number of flares operated by COMPANY at the Terminal Island with oil and gas processing, storage and export facilities, while considering ongoing and future developments on the island and possible integration with flare network of other downstream Company. The different flare systems cater to flaring requirements of HP, MP and LP systems in oil and gas processing plants at the island. The fundamental drivers for flare systems rationalization study are disadvantages associated with greater number of flares such as:

More plot area usage for flares at expense of industrial expansion Increased HSE risks in terms of thermal radiation and dispersion of toxic gases More fuel gas consumption as purge and pilot gas Higher operational and maintenance costs

In this study, existing flares at Terminal Island were studied and options were developed for each flare system with the aim of rationalizing the number of flares. These options included demolition of flares, diversion and redistribution of respective flare loads to other flares. Relocation of flares to offshore platforms / reclaimed areas in sea and replacement of elevated flare with enclosed ground flare, which has negligible thermal radiation was also considered.

The rationalization options developed for each flare system were evaluated on the basis of factors such as recovered sterile area, reduction in purge gas (Hydrocarbon and Nitrogen) and pilot gas consumption, maintenance cost, operation cost, number of flares and estimated investment as CAPEX (for modification scope). The current and future flare loads were taken into account while developing these options. The flare design capacities, available capacities for accommodating additional flare loads, sterile area freed along with minimization of associated dispersion and thermal radiation effects at ground level after demolition of flares were also considered for generation of suitable rationalization options.

A simplified and optimized flaring network at Terminal Island operated by COMPANY was developed by reducing the number of flares based on techno-economic screening, while safeguarding the operational and safety requirements. As concluded from the study, eight (8) nos. of flares occupying significant sterile radii can be demolished out of total fourteen (14) nos. of existing flares.

The sterile area recovered (approximately 77,000 m2) as result of flares rationalization is of great value and importance for building new facilities. The land recovered can be used for future developmental projects on the island instead of opting for land reclamation. In addition, COMPANY's objectives to reduce environmental impact, associated HSE risks and thermal radiation intensity at surrounding areas / facilities will also be achieved.
Integrated Automation and Data-Driven Workflow for CO2 Project Management – Case Study from a Smart Oil Field in the Middle-East
Authors: Rubio Erismar , Alklih Mohamed Yousef , Reddicharla Nagaraju , Albelazi Abobaker , Dilsiz Melike , Al-Attar Mohamed Ali , Davila Rayner , Khan Karem
Published: December 2021

Automation and data-driven models have been proven to yield commercial success in several oil fields worldwide with reported technical advantages related to improved reservoir management. This paper demonstrates the implementation of an integrated workflow to enhance CO2 injection project performance in a giant onshore smart oil field in Abu Dhabi. Since commissioning, proactive evaluation of the reservoir management strategy is enabled via smart-exception-based surveillance routines that facilitate reservoir/pattern/well performance review and supporting the decision making process. Prolonging the production sustainability of each well is a key pillar of this work, which has been made more quantifiable using live-tracking of the produced CO2 content and corrosion indicators.

The intensive computing technical tasks and data aggregation from different sources; such as well testing and real time production/injection measurements; are integrated in an automatic workflow in a single platform. Accordingly, real-time visualizations and dashboards are also generated automatically; to orchestrate information, models and multidisciplinary knowledge in a systematic and efficient manner; allowing engineers to focus on problematic wells and giving attention to opportunity generation in a timely manner. Complemented with numerical techniques and other decision support tools, the intelligent system data-driven model assist to obtain a reliable short-term forecast in a shorter time and help making quick decisions on day-to-day operational optimization aspects.

These dashboards have allowed measuring the true well/pattern performance towards operational objectives and production targets. A complete set of KPI's has helped to identify well health-status, potential risks and thus mitigate them for short/long term recovery to obtain an optimum reservoir energy balance in daily bases. In case of unexpected well performance behaviors, the dashboards have provided data insights on the root causes of different well issues and thus remedial actions were proposed accordingly.

Maintaining CO2 miscibility is also ensured by having the right pressure support around producers, taking proactive actions from continues evaluation of producer-injector connectivity/interdependency, improving injection/production schedule, validating/tuning streamline model based on surveillance insights, avoiding CO2 recycling, optimizing data acquisition plan with potential cost saving while taking preventive measures to minimize well/facility corrosion impact.

In this work, best reservoir management practices have been implemented to create a value of 12% incremental oil recovery from the field. The applied methodology uses an integrated automation and data-driven modeling approach to tackle CO2 injection project management challenges in real-time.
Hybrid Physics-Constrained and Data-Driven Approach for Interwell Saturation Estimation from Well Logs
Authors: Kovalev Dmitry , Safonov Sergey , Katterbauer Klemens , Marsala Alberto
Published: December 2021

Combining physics-based models for well log analysis with artificial intelligence (AI) advanced algorithms is crucial for wellbore studies. Data-driven methods do not generalize well and lack theoretical knowledge accumulated in the field. Estimating well saturation significantly improves if predictions from physical models are used to constrain data-driven algorithms in outlined primary fluid channels and other important points of interest. Saturation propagations in the reservoirs interwell region also generalize better under using combination of models. This work addresses combined usage of theoretical and data-driven models by aggregating them into single hybrid model. Multiple physical and data-driven models are under study, their parameters are optimized using observations. Weighted sum is used to predict water saturation at every point with weights being recomputed at each step. Model outputs are compared in terms accuracy and cumulative loss. A synthesized reservoir box model encompassing volumetric interwell porosity, resistivity and saturation data is used for the validation of the algorithms. Aggregated model for estimating interwell saturation shows improved prediction accuracy compared both to physics-based or data-driven approaches separately.
Very High Temperatures Steam Foam Additives
Authors: Odier Céleste , Kerdraon Margaux , Lacombe Emie , Delamaide Eric
Published: December 2021

In heavy oil reservoirs operated by steam injection, foam has a double benefit. By improving the steam sweep efficiency within the reservoir, foam increases oil recovery while reducing the amount of injected steam. However, in the field, this technology is not always very effective due to the fact that it is difficult to find foaming agents that can withstand temperatures above 200°C. Moreover, the agents that form stable foams at such temperatures are often insoluble at ambient temperature, and therefore difficult to solubilize in the field. Thus, a compromise between good solubility in surface conditions and high temperature foaming performances in the reservoir has to be found.

In this study, we show that it is possible to boost chemicals that form foam at very high temperature with an additive to greatly improve their solubility at ambient temperature while maintaining their high foaming performance at high temperature.

Two foaming agents of increasing degree of hydrophobicity (H and HH) were initially selected for this study. The first one shows high foaming performances in porous media and in a high-pressure cell at temperatures comprised in between 150 and 220°C. The second one, more hydrophobic, is particularly performant at temperatures comprised in between 220°C and at least 280°C.

Using a robotic platform, the temperature at which the foaming solution for agents H and HH needs to be heated to be solubilized, was evaluated with an accuracy of 5°C in four brines (varying salinity and hardness). We found that the temperature at which both agents become soluble is above 60°C, still too high for a field application.

In the second part of the study, these hydrophobic molecules were coupled to a pre-selected additive. The resulting mixtures were again qualified in terms of solubility and foaming performances. We show that by coupling these hydrophobic agents with an additive, we are able to maintain their excellent foaming performances while decreasing their solubilisation temperature down to room temperature.

To the best of our knowledge, this is the first time that very high temperature foam stability assessment up to 280°C is combined to solubility measurements to design performant foaming solutions that will be easy to handle in the field for steam foam applications. Interestingly, we show that the hydrophobicity of agents that is required for high temperature foam generation can be balanced by a more hydrophilic agent without reducing their foaming performances.
Associative Microgels, New Self Adaptive Systems to Control Fluid Loss in Well Cementing
Authors: Cadix Arnaud , Meeker Steven , Kaushik Swati , Haumesser Elodie , Ovarlez Guillaume
Published: December 2021

Fluid loss control additives are critical constituents in a cement slurry formulation to ensure even cement placement and ultimately satisfactory zonal isolation. Many technological options have been developed over the past decades to design fluid loss control additives for cementing. The most popular technologies as of today are either based on water soluble polymers or colloidal particles like latexes. As an alternative approach, in this paper we introduce a new technology based on associative or "sticky" microgels. These microgels are able to associate with one another at elevated concentration but, more surprisingly, are also able to associate under shear in the dilute regime during a filtration process. As a consequence these additives demonstrate outstanding performance as fluid loss control agents.

This study focuses first on standard API filtration tests using sticky microgels, and on how their behavior in application differs from traditional systems, in particular water-based soluble polymers such as cellulosic derivatives or synthetic polymers. Our investigations then focus on the working mechanism of the microgel system by analyzing adsorption on the cement surface, rheology, and filter cake structure using Mercury Intrusion Porosimetry (MIP). Finally the behavior of sticky microgels in model filtration tests is explored with either filtration against porous ceramic discs or using microfluidic chips allowing a direct visualization of microgels during filtration.

This study demonstrates that associative microgels are not controlling fluid loss through a simple size match between particles and pores within the filter cake but rather through shear-induced aggregation. Microfluidic observations reveal that aggregation occurs irreversibly as microgels are forced through the pores as the filtration process occurs. The shear-induced associated gels are particularly effective at reducing dramatically the filter cake permeability and allowing gas migration control. Interestingly the shear-induced aggregation of associative μgels seems to confer self-adaptive properties of the fluid loss additives with respect to the pore network to be clogged. Indeed, formation of shear aggregated gels larger than the individual microgels can be used to limit fluid loss even if the pore sizes are much larger than the individual microgels.
Systematic Modelling of Unstable Displacement
Authors: Skauge Arne , Sorbie Kenneth Stuart , Salmo Iselin Cecilie , Skauge Tormod
Published: December 2021

Modelling unstable displacement is a challenge which may lead to large errors in reservoir simulations. Field scale coarse grid simulations therefore need to be anchored to more reliable fine grid models which capture fluid displacement instabilities in a physically correct manner. In this paper, a recently developed approach for accurately modelling viscous fingering has been applied to various types of unstable displacement.

The method involves estimation of dispersivity of the porous medium and length scale of the model to determine the required size of the simulation grid cell. Fractional flow theory is then applied to obtain the correct saturation of the injected phase in the unstable fingers formed due to the adverse mobility ratio. Unstable displacement experiments have been history matched using 2D-imaging of in-situ saturation as a calibration of our method, before carrying out sensitivity calculations on the effect of fluid viscosity, and rock heterogeneity. Our modelling approach allows us to carry out simulations using a conventional numerical simulator using elementary numerical methods (e.g. single-point upstreaming).

The methods used to model instability (Sorbie et al, 2020) was originally developed for immiscible water/oil systems. The current paper now presents new results applying this approach to unstable gas displacements, where adverse viscosity ratios may be even higher than in water/oil systems. The displacement with injected gas is shown to be influenced by mass exchanges between the gas and oil as the alternating fluids (water and gas) are injected in WAG processes. Swelling of fingers delay the gas front and WAG processes divert the injected gas and improve sweep efficiency. We have also modelled water-oil displacement at adverse mobility and shown the benefit which is obtained by reducing the instability by adding polymers to viscosify the injected water. The impact of rock heterogeneity has different effect depending on buoyancy forces and the degree of crossflow into the high permeable zones.

This paper extends our novel approach to modelling the fine scale distribution of the injected fluids in adverse mobility ratio displacements. This approach has now been applied to both, gas/oil and water/oil systems where viscous fingering is present, either at extremely adverse mobility ratios and/or for reservoirs where the permeability field is very heterogeneous.
The Evolution of Green Completion in BP Khazzan Field
Authors: Al Harrasi Sultan , Jayawickramarajah Naren , Al Shidhani Taimur , White Daniel , Najwani Mohamed
Published: December 2021

Well Testing is the single largest contributor of carbon emissions during well operations and the industry's aspiration to reduce carbon emissions inspired the bp Oman team to identify innovative ways to reduce emissions from activities in the Khazzan field.

Khazzan is characterized by tight reservoirs which requires hydraulic fracturing to release gas from the rock. After fracturing, the wells are tested/cleaned-up by flowing the well fluids and flaring the produced gas and condensate to the atmosphere. The testing removes contaminants – proppant, frac fluid, hydrogen sulphide – that could damage the downstream Central Processing Facility (CPF). ‘Green Completion’ was one of the opportunities that was identified by the bp's Oman team to remove these contaminants in an environmentally friendly manner.

A Green Completion is a zero flaring concept – hydrocarbons produced during well test operations are ‘cleaned’ and then routed to processing facilities for export rather than being flared. This concept has been successfully utilized in bp's onshore US operations for over a decade. The team leveraged the experience from the USA, applying this technology to suit the conditions in Oman, but it was not simple nor straight forward. In the last two years, this process has been modified and reinvented for the operations in Oman as the company seeks to strategically reduce its global carbon footprint.

In first half of 2018, the bp Wells team initiated a pilot project with the objective of developing Green Completion capability in the Khazzan field. This was the start of the journey to demonstrate bp's commitment to reducing greenhouse gas (CHG) emissions in a sustainable manner. Furthermore, bp's collaborative cross-functional aptitude allowed for expanding the use of Green Completions into the Ghazeer development, which enabled zero-emission well testing of newly drilled wells even before commissioning of the new pipeline infrastructure. Through this initiative, the region has reduced emissions and generated cash by selling the recovered hydrocarbons instead of flaring into the atmosphere during well testing operations. Since Q1 2019, the total reduction of CO2 emissions exceeded 240,000 tonnes of CO2 equivalent, which equates to taking circa 52,000 vehicles off the road for one year.

The implementation of this environmentally friendly operation also adhered to strict safety standards. The rigid bp safety process guidelines ensured that all challenges and optimization opportunities were fulfilled in a safe manner.

The purpose of this paper is to detail how the team pushed the technical envelope to introduce this technology and share the journey entailing extensive cross-disciplinary cooperation amongst operations, subsurface and wells teams to fulfill the zero emissions objective.
The Use of 5G Technologies in the Digital Transformation of the Oil/Gas Industry
Authors: Al-Jadir Sadik Jadir
Published: December 2021

Many oil & gas companies embarked on their Digital Transformation (DX) journeys with rapid adoption of emerging digital technologies. Successful digital transformation initiatives are necessary for Oil/Gas Companies to improve efficiencies, streamline their operations and meet pressing challenges for cost reduction, increased efficiency, and improved safety.

Oil & Gas fields and processing facilities require robust and reliable telecommunication infrastructure to support the application of much needed digital technologies. The availability of high-speed connectivity has been a challenge for many Oil/Gas companies operating in remote or hazardous locations. The latest Fifth Generation cellular technology (5 G) addresses such essential Oil/Gas requirements as increased speeds/bandwidths, very low network latencies, ultra-reliable communications, and the capacity to handle large number of users.

5G is designed around following technologies: Small (micro) cells requiring less power,Higher frequencies offering bigger data handling capacities,Cloud and Edge Computing for low network latencies and added security.

These 5G design features will enable numerous Oil/Gas applications such as Industrial Robots/Drones, Virtual/Augmented Reality, Video Surveillance with Artificial Intelligence (AI) features (Face Recognition, Object Recognition & intelligent Image processing), Remote Asset Management, Industrial IoT communication between Sensors, Gateways and Device Controllers, Pipeline Leak Detection Systems, Telemetry and SCADA. 5G is therefore poised to be a key enabler in Digital Transformation.

The UAE has an advanced telecom infrastructure that offers customers high speed fibre optic connectivity. UAE telecom operators have also been quick to deploy 5G in main cities. Etisalat for example is running a 5G pilot on Das Island with ADNOC Offshore and a major Network Supplier to test potential use cases of the technology in the O&G industry.

The push for 5G in O&G will benefit from cooperation between the O&G industry, the telecom operators and technology providers. The role of Governments and the Telecom Regulators can further accelerate adoption through allocation of frequency spectrum to enable 5G Private Network model of deployment. The private network model is crucial for the Oil & Gas industry in view of the special requirements, nature and remoteness of oil and gas installations.