bluuebunny/crossref_metadata_2025 huggingface dataset:
Foundational Study of Artificial Intelligence Reservoir Simulation by Integrating Digital Core Technology and Logging Data to Optimise Recovery
Authors: Lener Alberto
Published: October 2022

In strategising development of hydrocarbon reservoirs, substantial uncertainty in recovery potential is often attributed to subsurface heterogeneity. Challenged reservoir characterisation is proposed to be directly due to the inability of correlating spatial scales: core analyses to well logging data. This study’s central goal is to propose a ‘Multiscale link’ by challenging empirical correlations of multiphase displacement and ‘upscaling’ processes of reservoir characterisation by exploiting Artificial Intelligence and ‘Digital Rock Technology’, aiming at minimising geological risk.

By exploiting 40 years of a North Sea field's appraisal and production and formulating an AI-compatible ‘multiscale’ data set, petrophysical correlations have integrated a further innovative concept: borehole image processing to characterise geological features and oil potential. In binding the ‘Multiscale’, fundamental multiphase dynamics at pore-scale have been critically associated to most affine reservoir modelling ‘deep learning’ frameworks, leading to ideating an AI workflow linking field-scale rates, well logs and core analyses to the continuously-reconstructed pore network, whilst extracting invaluable multiphase dependencies.

The preliminary results implementing selected Machine Learning algorithms, coupled with advanced digital technologies in reservoir simulation, have been showcased in proposing a solution to the ‘Multiscale link’ in reservoir characterisation, providing the groundworks for its programming realisation. Importantly, it was concluded that the layers of complexity within learning algorithms, which constrained its execution within this project, undoubtedly require multidisciplinary approach. By conceiving a physically and coding-robust workflow for advanced reservoir characterisation and modelling permitting ‘multiscale’ representative multiphase simulations, identification of optimal EOR becomes attainable.

This leading edge represents potential to minimise geological risk, thus de-risking reservoir management (in turn FDP) of mature and live fields; but also expected to set a starting point for further developments of Artificial Intelligence in the oil and gas industry.
How Digital Twins Will Help to Unlock United Nations Sustainable Development Goals
Authors: AlAmir Noora
Published: October 2022

This study analyses the need to overcome barriers in the path to adoption of digital twin technology by oil and gas companies thereby achieving value maximization for investments. Case studies provide evidence for demonstrated achievements in terms of corporate sustainability, while pursuing the adopted United Nations Sustainable Development Goals, thus highlighting the existing and future possibilities made available by Digital Twin technology – building the case for digital twin technology as a breakthrough technology. In order to enhance efficiency, and safety, the hydrocarbon industry is looking at a wide range of digital technologies, including machine learning, artificial intelligence (AI), Internet of Things (IoT). It is becoming increasingly common for the hydrocarbon industry to use data-oriented solutions as a means to improve performance, efficiency, and cost-effectiveness. Understanding such complicated systems necessitates the simultaneous examination of data gathered from numerous sources. The next era of large production monitoring and efficiency systems will be based on Digital Twin (DT) modelling. From underground equipment to central production plants, it is part of a productivity-boosting solution that integrates data, simulation, and visualization. Hydrocarbon Exploration can greatly benefit oil and gas companies if these cutting-edge technologies are properly utilized in addition to pursuing the adoption of UN SDG vision. There are many ways in which this study aims to incorporate digital technology into hydrocarbon exploration, drilling and production. This study investigates the necessity of oil and gas companies overcoming obstacles and create an ecosystem that stand in the way of their adoption of digital twin technology in order to maximize the value of their investments and achieve value maximization.
Advantages of a Compositional Framework for Well and Surface Network Modeling
Authors: Mogensen Kristian , Samajpati Swarjit
Published: October 2022

Integrated asset models are being constructed for all ADNOC assets as part of a production optimization initiative supported by a significant digitization effort. Contrary to the standard industry practice of utilizing black-oil formulations to capture fluid behavior, a compositional modeling framework was selected to address some key challenges: Compositional variation at reservoir-level, either lateral or verticalInjection of gas (immiscible as well as near-miscible) causing mass transferBlending of different fluids in the surface network at line conditionsOperational requirement to maintain the bottom-hole pressure above saturation pressureValidation of raw well test data before shrinkage correction (line conditions)Investigation of impact of changing separator settings (affecting shrinkage correction)Tracking of fluid composition in produced streams

The compositional framework is very comprehensive. For each of the 100+ producing reservoirs, one or several equation of state (EOS) models was developed. In every well, an initial fluid composition estimate was provided as an anchoring point, which was subsequently adjusted in a tailor-made workflow to match the solution gas-oil ratio measured in the field by performing an isothermal flash of the original composition and then recombining the flashed oil and gas streams to the field gas-oil ratio.

The workflow offers a number of advantages, one of which is that the path-to-surface correction can be imposed directly on field measurements. This has resulted in much improved allocation factors for oil, gas, and water. Fit-for-purpose algorithms have been developed to perform well test validation for different well types based on raw data at line conditions.
Electrification in Industry: The Most Efficient Way Towards Decarbonization
Authors: Diezinger Stefan , Dennhardt Benjamin
Published: October 2022

Electrification of process industries (e.g., oil & gas, chemicals, pulp & paper, steel, cement, etc.) will be key to meeting emissions targets established in the Paris Climate Accord. Organizations across several sectors are making progress on this front, particularly in Europe where carbon taxation heavily incentivizes emissions reductions measures. However, today, the overwhelming majority of mechanical power and heat generated globally for industrial processes still comes from fossil fuels (i.e., gas turbines/engines, coal or gas-fired boilers, etc). Electrifying these assets with renewables or other low- carbon energy sources is an important step on the decarbonization journey but it can present many challenges for operators.

This paper presents various possibilities for electrification of the production of heat and mechanical power in industrial applications. For power, the replacement of gas and/or steam turbine mechanical drives with electric motors is discussed, as is the potential for hybrid (i.e., dual drives). The use of industrial heat pumps and electric heaters as a replacement for gas-fired boilers/furnaces is also discussed. Drawing from real-world applications, the paper aims to show how these technologies can be applied economically and also outlines potential hurdles that need to be addressed to make a compelling business case for electrification, particularly in brownfields.
Digitizing Drilling Process Using Low-Code Cloud Powered Solution
Authors: Alshardi Sultan , Asemebo Ericson , Acheerakath Shabeer , Ismail Ahmed , Elabsy Eslam , Alshkeili Anoud
Published: October 2022

This paper will demonstrate how digitizing drilling operations and addressing operational inefficiencies through a cloud-powered solution, can increase efficiency and profitability. Control the drilling operation was previously considered a complex task and utilized conventional methods. However, with high operational demand, digitizing the end-to-end process and integrating all stakeholders into one platform, ultimately allowed the workflow to be standardized.

The entire workflow was automated using the Agile methodology and the low-code platform, PowerApps. The solution has streamlined operations and resolved the difficulty in obtaining accurate and instantaneous information by using a single platform and establishing an efficient event driven workflow.

The solution integrated eight applications that cover: contract review, scope of work, well planning and design, base and location preparation, job execution, along with post job activities, and performance validation.

The event-driven workflow eliminated transactional errors and enhanced the flow of information and data between different disciplines within the drilling group. This was achieved by digitizing the complex processes across several stakeholder bodies and integrating the workflow into one comprehensive platform.

The digital solutions, such as this one, can be applied to the oil and gas industry are representative of the advancements that can be made when leveraging cost-effective solutions.

Initially, by aligning expertise from different disciplines (business context, IT collaboration, strong system integrators and a state-of-the-art technology platform) the necessary elements were present to achieve success. Secondly, the 6-month turnaround time to design and implement the solution was achieved by customizing the low-code PowerApps platform and integrating it with the master and sub-application principles, enabling application developers to reduce complexities and produce powerful results.
Integrity Challenges and Restoration of Sub-Surface Safety Valves by Innovative Rigless Techniques
Authors: Ahmad Zeeshan , Al Hosini Abdullah Alhaj , Al Janahi Mohammed Ibrahim , Al Marzouqi Abdulla Mohammed , Siddiqui Muhammad Ali , Al Zarouni Abdulla Haidar Abdulla , Alhamadi Reem Mohamad
Published: October 2022

Sub-surface safety valves are the integral critical part of the well integrity management and their functionality cannot be compromised at any stage of well life. Unavailability of SSSV's due to integrity issues company was facing serious challenges in production and well availability during high gas demand. Moreover, workover solution led to 7-8 months for completion of workover and reinstatement of surface facilities. In this paper, case studies of different integrity related problems with sub-surface valves discussed and extensive study conducted to restore the critical sub-surface safety system. These case studies highlighted encountered problems such as landing nipple profile damaged due to corrosion/scale, movement of SSSV from its profile, broken flapper during hydraulic frac operation and conversion of TRSSSV to insert type with challenging well interventions issues.

High pressure gas well was restored with redressed SSSV by using nipples gauge hanger above the valve to avoid any jumping of newly installed valve due to nipple profile washed out limitation. Insert type valve option evaluated for the same well with 40 MMSCF/D flow and concluded not suitable due to production constraints as ID of IVC was less than 2" which may be suitable for low producers.

Special KMH tool designed and E-line utilized for real time monitoring during trouble shooting of TRSSV with broken flapper and successfully resumed the well accessibility for workover operation. Wireless technology can improve the accuracy of response and safety system of wells with limitation of relatively less flow specially in gas wells with scale challenges. Such approach may avoid the work over in case of more accurate control.
Sustainable Removal of Re-Occurring Scale & Corrosion Products by Textural Analyses Using Petrographic Thin-Sections: A New Cross-Disciplinary Application of a Traditional Geological Technique
Authors: Hujer Wolfgang , Kadnar Rainer , Hönig Stefan
Published: October 2022

Corrosion and scale products are frequently encountered in the oil & gas industry and often are main concerns regarding flow assurance. They form due to chemical conditions that are in most cases not within the operational specifications. The same chemical conditions are quite often also responsible for corrosion failures. Removal of scale and corrosion products is often a time-consuming process including a significant proportion of human work in areas with high HSSE-risks; e.g. cleaning of tanks. Furthermore, the interruption of production processes is generally accompanied by financial losses. Scale and corrosion products form due to environmental conditions that are often outside the normal operating conditions (Burns, 2016). Therefore, identifying those conditions can be very challenging and if the reason(s) for scale/corrosion product formation are not discovered they are likely to occur again. The detailed analyses of the texture as well as mineralogical-chemical composition of scale and corrosion products and fluids present can provide valuable information on formation conditions. This information can be crucial to identify reasons for scale precipitation or corrosion thus providing involved experts with the knowledge to prevent recurring issues with both.

However, our own experience has shown that analytical programs of scale & corrosion products are often not designed to answer the most important question why they have formed are missing. This can result in reoccurring formation of scale & corrosion products and repeated cost-intensive removal.

Three crucial points have been identified strongly influencing the quality of scale & corrosion product analyses and interpretation. These points are:

Sampling Analytical methods used Interpretation of results

In course of the described case studies, a work-flow has been used that aims to ensure to avoid any failures in the identified crucial points. This work-flow will be discussed based on the experiences from the case studies with special emphasize on description of sampling, application of individual analytical methods including utilization of petrographic thin-sections and integrated interpretation of the results together with the customer.
Unlocking Oil Reserves from Inaccessible Platforms Utilising DSL (First Implementation in Egypt)
Authors: Koriesh Mahmoud Mohamed , Elwan Mahmoud , Shahin Eman , Basyouni Ali , Soliman Hamdy , Okasha Osama , Saleh Mohamed , Heaney Frank
Published: October 2022

Offshore Oil accounts for 30% of the world's liquid hydrocarbon production. As offshore platforms age, as is the case with some of the production facilities in the Gulf of Suez, these structures will have a increased load restriction, which makes it difficult to perform simple interventions, and forces the operator to deploy a Jackup rig or do a barge assisted operation. Some identified opportunities are not performed due to the high cost and the inherent subsurface uncertainty with brownfield assets. An alternative solution is a new generation intervention tool that allows signal transmission on conventional slickline wire.

Real-time slickline (DSL) perforations use a unique technology to allow signal transmission on a standard slickline. The technology uses downhole battery-powered telemetry embedded in the downhole tool string. A radio-frequency (RF) antenna installed below the stuffing box is responsible for sending & receiving RF signals through the wire. The wire is coated with a proprietary engineered coating to ensure quality signal transmission and protects against corrosive wellbore fluids. The technology allows real-time depth correlation, pressure, temperature & vibration measurements while perforating. Moreover, the technology offers on-command explosive triggering, which improves safety over the older memory/timer version.

Real-time slickline perforating was successfully introduced in the Gulf of Suez, accessing two platforms with structure load weight limitations that could not accept a conventional e-line unit. The optimized weight of digital slickline equipment was only 8 tons, compared to 35 Tons for e-line. Two wells were successfully perforated on two different platforms, adding 1200 BOPD at 10% of the rig-assisted intervention cost. The real-time slickline deployment enhanced the intervention efficiency and saved $950,000 in operating expenses.

In addition to the successful deployment of several perforation runs without operational problems, the additional capabilities of DSL for surface readout (SRO) pressure & temperature data allowed the operator to optimize the time on the platform and maximize efficiency. The ability to add feedthrough jars to the string helped complete one job when the tool BHA struggled to get into the tubing after perforation. This capability is not available in conventional E-line.

Real-time slickline (DSL) operations are the next generation for rigless interventions providing access to wells that e-line could not cost-effectively intervene and complete this task at a much lower cost.
Implementation of Autonomous Ground Robots on Operational Sites
Authors: Bartoli Eric , Munoz Jean Michel , Audouin Gregoire , Collin Gildas
Published: October 2022

One of the missions of the TotalEnergies’ R&D is to pave the way for tomorrow's simpler, streamlined and less expensive facilities. The vision is focused on unmanned installations in which autonomous ground robots are key components.

In 2017, the ARGOS (Autonomous Robots for Gas and Oil Sites) Challenge delivered the first prototype of a new generation of autonomous, ATEX-compliant ground robots capable of detecting anomalies.

Based on this success, TotalEnergies started a few projects with the aim to introduce and standardize robotics on O&G sites.

The first project is the development of a series of autonomous robots, designed to withstand the rough O&G environment for long durations: an inspection robot and an operator robot.

The second project is the adaptation of the standard methods of engineering operations for green-field developments as well as preparing the implementation of robots on brownfields.

The third one is the development of a specific environment to remotely supervise a fleet of robots operating simultaneously on a same site.

A major take away for the success of robotics implementation is increasing the technological readiness as well as usability and acceptance of the whole robotics operation system. This can be verified only through exposure to users in a realistic environment.

After each major development, their proper achievement is measured following a robust process of observation in different contexts. An incremental approach for trials was implemented from testing in specific laboratory conditions up to long duration pilots on major installations under the custody of the future users. Those complex tests are a tremendous source of deep insight in understanding robotic operations and allowing the research to be pushed further towards a more practical solution for the petroleum industry.

The presentation will highlight the first tangible results from the operational implementation and prototypes testing of robots and the readiness of robotics for Oil and Gas.

The experience gained by TotalEnergies in developing Robotics Operations through testing it extensively in various industrial contexts, represents a unique case with this large scale of usages. It was already shared with some of our peers and this paper is a great opportunity to expose to the Oil and Gas industry to our vision of how to prepare the future of unmanned, safe and environmentally friendly operations.
Curing Packer Leak Riglessly Using Bismuth: Results of the Field Pilot
Authors: Yugay Andrey , Ahmad Bilal , Akhtar Mohamed Masud , Vorozhikhin Sergei , Almuharrami Abdulla Omar , Nadeem Amir , Varshney Mayank , Agarwal Apurv , Al Harmoodi Eisa Abdelaziz Abdalla
Published: October 2022

The concept of the well double barrier envelope is a common industry practice and main philosophy of well integrity discipline. This is well-described in some of the international standards: API RP90 (1 & 2), Norsok D10, ISO 16530 (1 & 2).

This double barrier policy applies to wells with positive pressure at surface capable to flow naturally. Primary barrier envelope consists of well equipment which is continuously under pressure and in direct contact with hydrocarbon. In case primary barrier element fails, secondary barrier envelope will be the one exposed to well media and holding the pressure. This content of this paper is related to such kind of wells that can flow naturally and should comply to the double barrier policy.

Any failure in the primary barrier envelope (means - completion) normally is addressed during workover by simply re-completing the well with new completion (after retrieval of the old one). This can be done almost unlimited number of times, as long as there is a place to set the packer. Failure in the secondary barrier envelope (means - casing) can be repaired as well, but not that easy and very limited amount of time. In some cases, especially for onshore wells it might be economically more reasonable to drill the new well rather than to deal with complicated workover. Depending on the Company policy, casing integrity can be restored in sections using casing patches or the entire length can renewed by running and cementing casing of smaller diameter. Obviously, in both cases it impacts the size of the completion, further well objectives and cannot be done multiple times.
Be in Control of Your Operation - Integrating Real-Time Optimization with Advanced Process Control for Optimum Energy Management and Optimization
Authors: Singh Arvin
Published: October 2022

Owner operators are tasked with the challenge of maximizing energy efficiency and overall energy management for highly complex and integrated operations, to which the downside has cost industry millions of dollars yearly. To realize optimum value of energy management and optimization, delegates will see how real time optimization is crucial with respect to advanced process control for complex operational conditions - not just integration, but what" to do" and "not to do".

Using an integrated approach of real-time optimization and advanced process control, delegates are shown the value of advanced process control, and under what scenarios real time optimization supports, compliments, and drives the overall energy optimization opportunities operationally. Demonstrated through successful industry use cases, the focus will be on identifying the right architecture and the right decision-making processes required for optimum energy optimization, including core considerations and limitations faced by the industry. Further, this paper will explore and articulate operational challenges faced during design, implementation, and scaling - providing delegates the insight to both the risk and reward.

This paper will detail the result of successfully integrated real time optimization and advanced process control architectures, providing different levels of return to operational requirements and complexity. Using core industry use cases, delegates will be able to see both the successes and lessons learned of the applied architectures reflecting different operational conditions. In conjunction, this paper will re-emphasize the design and deployment requirements for success, pivoting around the limitations of advanced process controls within certain operations.

To this effect, this paper will highlight the main return on investment opportunities to delegates, focusing on maximizing profits and production whilst minimizing overall utility costs. With complex integrated operations, delegates will get an insight into these tangible potentials and how they can benefit from different architectures which address different operational requirements from an energy management and efficiency domain.
From Drawing Board to HP award, the Success Story of Annular Injection Mixer (AIM) Using CFD
Authors: Maktar Fariz , Chauvet Christian , Sabey John
Published: October 2022

Annular Injection Mixer has proven to have superior performance in providing rapid and uniform vaporization of liquified petroleum gas (LPG) fractions into natural gas. This article focuses on presenting the validating process of evaporation performance of Annular Injection Mixer (AIM) via computational fluid dynamics (CFD) simulations to meet client requirements. Evaluating the dynamics and kinetics characteristic of droplets’ evaporation has always been a challenging aspect. This is where CFD simulations had the leverage over the conventional 1D process simulators.

This challenge was tackled in two steps using CFD simulations. The first step was the determination of droplet size distribution. Multiphase modelling was conducted with Volume of Fluid (VoF) model. A buffer zone was introduced downstream of the "knife-edge". In this buffer zone, an in-house script was developed to instruct the CFD software to generate droplets based on the incoming liquid characteristics. With information such as liquid volume, surface tension, and liquid velocity within this buffer zone, the droplets’ size was determined and reinjected into the domain as Lagrangian particles.

The second step was modelling the droplets’ secondary break up and evaluating the droplets’ evaporation. Droplet size distribution measured from the first step were reinjected downstream of the "knife-edge". Based on the latent heat of vaporization and local flow conditions surrounding each droplet, droplet break-up and later evaporation into natural gas were simulated. Evaporation length and homogeneity of LPG vapour within the natural gas were some of the other crucial criteria evaluated. These steps were conducted at each extremity of the operating envelope ensuring a consistently reliable and robust vaporization performance of the AIM.

Additionally, the CFD setup was fine-tuned, through adjustment of the Weber number, and validated through flow loop testing. The commercial system resulting from the initial CFD study and technology optimization has been in operation for more than 2 years.

This methodology of validating the AIM evaporation performance via CFD has not only provided prompt responses to any client operating needs but also has reduced the development cost and lead time by minimizing experimental assessments. This innovative approach in AIM development has led to multiple awards accumulated over the years, most notably, the Hydrocarbon Processing (HP), downstream processing sector's leading technical journal, awards for Best Gas Processing LNG technology in 2021.
A Successful Rigless Water Shut Off Solution in an Open Hole Horizontal Water Injection Field in the Sultanate of Oman Using a Water-Swelling Polymer System
Authors: Khalil Mohamed Amin , Al Kharusi Sharifa Nasser , Persac Stephen , Al Harthi Hamood , Al Naabi Ahmed , Al Mufarji Hilal
Published: October 2022

Premature water breakthrough between injector and producer wells through natural fractures can be a significant challenge leading to poor waterflooding performance in fractured reservoirs. Thus, applying a cost-effective Water Shut-Off (WSO) technique to stop injected water from flowing into fractured zones has become paramount to increasing production from mature fields and enhancing hydrocarbon recovery from such reservoirs by modifying the injection profile.

This paper presents a successful chemical WSO solution designed to help improv injection systems’ sweep efficiency by stopping injected fluids in waterflood fields from flowing into fractured or highly vugular zones, leading to direct communication with the producing wells. Each water injector well supports two to three oil producers forming a horizontal waterflood pattern. Since the early days of injection, water cut has increased dramatically, reaching almost 100% in some producers to indicate direct communication through the fracture network.

The treatment consists of bullheading a water-swellable agent into the injection well along with an aqueous solution to swell the agent. The agent is a synthetic polymer capable of absorbing 30 to 400 times its weight in water to seal off the fractures without penetrating most matrix systems. The carrier fluid helps determine the agent's swelling rate, and a shutoff period is required to give enough time for the polymer swelling to take place.

After the treatment, the injection pressure response was observed between 200 psi to 600 psi at the same injection rate. Water cut dropped gradually; a drop of 0-15% in water cut was observed in the nearby producers, resulting in an oil gain up to 100 Bbls in some of the oil producers. The result was a cost-effective treatment, producing more bbl. of incremental oil in one year.

This paper will discuss the job planning process along with the treatment design. The treatment execution is summarized, followed by the results obtained from the job's realization with key lessons learned and recommendations.
Enhancing Power Generation Utilizing Turbine Inlet Air Cooling (TIAC)
Authors: Kutbi Jehad Fawzi , Georgiou Ioannis
Published: October 2022

Electricity demand is growing globally due to increasing population and growing economy, it is projected that the global energy demand will increase by 2.3% a year. One of the most reliable ways to generate electricity is by using gas turbines. Although gas turbines are efficient in terms of generating electricity, their power output significantly varies throughout the year due to temperature variance, especially in the summer time where the temperature can reach up to 50 C°. This is because gas turbines power output is proportional to the mass flow of air/fuel through the engine. Since the volumetric flow of air through the engine is essentially constant, mass flow therefore changes with temperature of the air entering the compressor of the gas turbine. When the ambient temperature is high, the power output and efficiency are reduced. Thus, by cooling the gas turbine inlet air, the turbine power output is significantly increased and its efficiency improves. Cooling the combustion air even by few degrees can improve the power output substantially. This is because cool air is denser and therefore gives the turbine a higher mass flow-rate and pressure ratio, resulting in increased turbine output and efficiency as much as 0.5% per degree Fahrenheit or about 1% per degree Celsius. Another advantages in cogeneration is the higher exhaust mass flows resulting in more steam generation. Turbine inlet cooling can be installed in most of the turbines of Saudi Aramco in order to increase their nominal capacity and improve their NOx emission. This paper will analyze the mechanism behind the turbine inlet cooling and will presents the results of a techno economical study conducted for retrofitting a TIAC system on the existing GE Frame VII gas turbines of Abu Safah and Qatif plant facilities.
Innovative Approach to Develop an Old Complex Reservoir Bearing Multi-Billion Barrels of Reserves in a Middle-East Carbonate Field
Authors: Younes Dania Wayel , Keshtta Osama Mohamed , AlAmeri Khaled Husain , Bigno Yann
Published: October 2022

This paper showcases the development approach recently adopted in an offshore reservoir bearing multi billion stock tank barrels of oil-in-place that solely depended on natural depletion starting from the year of 1962 until the introduction of the crestal gas injection mechanism in 1994, yet less than three percent of this potential has so far been recovered! This low recovery can be justified by the very complex nature of this reservoir varying from the expected highly fractured crest to the very poor characteristics of the matrix spreading towards the down flank, in addition to the high competition between this as a lazy reservoir and the other high potential reservoirs to produce against a high-pressure system of surface facilities. Even though the very first oil shipment in 1962 from this field was exported from this reservoir, all these surface and subsurface bottlenecks have been making its development so challenging that it had to be put to a halt yielding a hydrocarbon recovery that is less than three percent of its potential in the past 60 years.

A new development approach was adopted in this reservoir introducing the line drive water injection mechanism as a basis for all future development, in addition to introducing artificial means in order to overcome the high-pressure system of the existing surface facilities. Several uncertainties were encountered linked to this type of development plan for this type of complex reservoir such as well spacing (OP/WI), well architect (short horizontal vs. MRC/ERD vs. deviated), well completion, well productivity/eruptivity and for water injection as it is the first time to inject water in this type of reservoirs water injectivity, water quality, scale risk..etc. So, a dedicated de-risking plan was introduced & implemented to try to overcome and mitigate all these challenges and risks before full implementation of the proposed development plan.

The line drive pilot (OP/WI) plan was implemented mirroring the future long term development plan for the main purpose of proving the economical feasibility of the line drive recovery mechanism in such a reservoir while maximizing the acquisition of associated static and dynamic monitoring data. This will ultimately appraise and feed into the long-term development plan set for this reservoir while paving the way for it to reach its true potential and meet its future production target.

This paper discusses both the de-risking pilot design and its results, which overall, support the implementation of this development plan. The pilot was started with the oil producer since Aug-2020 followed by the water injection since Mar-2021.
Re Configuring and Restaging Centrifugal Compressors for Depleting Reservoir Pressures
Authors: Sahadevan Roy
Published: October 2022

Compressor stations are essential to export natural gas through pipelines. Gas reservoirs deplete over the years, as a consequence, gas compressor stations experience a lower-than-normal suction pressure. Hence it becomes increasingly difficult for the existing compressor hardware to export gas to destination.

Variable speed compressors are designed with certain amount of flexibility to accommodate changes in inlet pressure conditions. However significant changes in inlet operating conditions, because of reservoir depletion, adversely affect natural gas export through centrifugal gas compressors.

This prompts operating companies to develop alternate solutions to export low pressure gas. In the process, compressor modification opportunities need to be identified, developed and be applied to facilitate gas export at revised inlet conditions, either by changing pressure ratio across the compressor or gas flow rate or both. Rearranging parallel compressors to series operation is one of the likely methods of achieving higher pressure ratio for gas export. Restaging of existing compressor may also be required to optimize compressor operation.

Cost effective projects are delivered by lining up the compressors differently and by changing compressor internal stator and rotor components to suit new operating conditions, avoiding off-design operation, and allowing the modified compressor to operate in an envelope with increased operational efficiency. This is also known as upgrade or re-rating of compressors.

The paper is about rearranging and restaging existing gas compressors in onshore gas compressor stations, to export natural gas, when the gas wells experiencing significant pressure depletion.

The paper explain method of establishing maximum gas export rate, highest pipeline back pressure for gas export and the compressor discharge pressures at battery limits. The adequacy checks are performed on compressors, motors, and all associated auxiliary systems.
A Fit-For-Purpose ESP Technical Solution Enables 17% Production Increase in Complex Reservoirs in Mature Fields in Ecuador
Authors: Leon Fernando , Pancho Juan , Franco Ernan , Balseca Diego , Ruales Fernando , Quinzo Maria Elena , Perez Mauricio , Villalobos Jorge
Published: October 2022

A fit-for-purpose electrical submersible pump (ESP) technical solution, based on a combination of pump types and an innovative extended gas-handling device resulted a production increase of 17% in four mature fields in Ecuador. The extended gas-handling device enabled a superior performance of ESP systems to decrease downhole parameter fluctuations normally observed in challenging production conditions to improve oil production.

Historically, ESP operations in mature fields in Ecuador have posed extremely demanding conditions, where reservoir depletion generates lower static and flowing pressures that are typically associated with an increment in free-gas content in the produced fluid. Low flow rates, high lifting requirements, and high gas content degrade ESP performance and reliability while complying with field economics.

This innovative ESP technical approach improves fluid hydraulics through the pump by combining a newly developed extended gas-handling device with proper selection of pump stage models to avoid production losses due to gas blockage, leading to an increase of pressure drawdowns and the maximization of flow rates. Additionally, when the reservoir has had a fracturing job to improve its productivity, the ESP selection process becomes even more challenging. Therefore, this ESP configuration incorporates a robust technology to face abrasive conditions, and flow rates are thoroughly controlled during the well's initial production phase to mitigate excessive migration of proppant into the pump. The technical solution developed has helped to increase production and improve the equipment reliability. On the 47 wells where this technology was successfully adopted, a 17% increase in oil production was observed and was attributed to the system's capacity to maximize reservoir drawdowns, with intake pressures as low as to 150 psi, while maintaining stead operation in gassy conditions. The enhanced equipment performance obtained with this technology contributed to a reduction in the number of ESP failures having as root cause low productivity, which decreased from 34 in 2019–2020 to 16 in 2021–2022 with zero ESP-related failures recorded among the 47 wells where this technology was installed.

This innovative ESP configuration has emerged as a pioneering solution in the region to fulfill challenging production conditions in mature fields where a cost-effective solution is required. Furthermore, it opens a new spectrum to maximize oil production in mature fields by expanding the currently understood technical boundaries for ESP operation in low-flow gassy applications.
An Effective Method of Estimating Nuclear Magnetic Resonance Based Porosity Using Deep Learning Approach
Authors: Tariq Zeeshan , Gudala Manojkumar , Xu Zhen , Yan Bicheng , Sun Shuyu , Mahmoud Mohamed
Published: October 2022

Carbonate rocks are very heterogeneous and have very complex pores structure due to the presence of intra-particle and inter-particle porosities. This makes the characterization and evaluation of the petrophysical data, and the interpretation of the carbonate rocks a big challenge. Porosity in complex lithologies, particularly carbonate reservoirs, is difficult to measure using conventional (Quad-Combo) well logs. Nuclear Magnetic Resonance (NMR) derived porosity is considered the total porosity "gold standard", as it is measured exclusive of matrix and mineralogy. However, due to NMR tools existing as relatively new technology, and the extra expense in logging runs and rig time, most wells lack these data. Most of the existing approaches to predict the rock porosity was developed on the Neutron-density porosity logs that usually are resulted in inaccurate estimation, especially in the fractured zone and highly dolomitized rocks. In this study, deep learning model was efficiently utilized to predict the Nuclear Magnetic Resonance based effective porosity in carbonate rocks. The petrophysical well logs such as bulk density, gamma-ray, neutron porosity, photoelectric log, and caliper log were used as predictors. A total of 3800 data points were obtained from several wells located in a carbonate reservoir. A comprehensive data exploratory analysis tools (EDA) was utilized to evaluate the quality of the dataset which led to removing the extreme values and outliers. A fully connected Deep Neural Network (DNN) was trained to predict NMR based effective porosity. The hyperparameters of DNN model such as number of hidden layers, number of neurons, activation functions, and learning algorithms were varied using a grid search optimization approach. The K-fold cross-validation criteria were used to enhance the generalization capabilities of ML models. The evaluation of ML models was assessed by the coefficient of determination (R2), root means square error (RMSE), and. average absolute percentage error (AAPE). The results showed that the DNN resulted in a significantly low error and high R2 between actual and predicted values. An accuracy of 87% was recorded between actual and predicted NMR values. The new model to predict the NMR porosity is trained on the NMR-determined porosity. NMR porosity is based on the number of hydrogen nuclei in the pore spaces that are independent of the rock minerals and related to the pore spaces only.
A Practical Capacitance–Resistance Model Approach to History Matching and Full Field Chemical EOR Forecasting
Authors: Al-Rawahi Hamza Salim Humaid , Groenendijk Dirk Jan , Wunnik Johannes Maria van , Mahruqi Dawood Ahmed Al , VanBatenburge Diederik , Karpan Volodimir , Al-Abri Mohammed
Published: October 2022

Commercial application of chemical flooding requires understanding the performance of patterns already subjected to water- or chemical flooding and the capability to extrapolate this performance to new patterns. The conventional approach that relies on complex finite-difference models to obtain oil profiles is time-consuming and often unable to provide a good match on a well-by-well level. The workflow developed here instead starts from the well-by-well level, using a Capacitance Resistance Model (CRM) and oil response type curves to allocate gross rates and generate oil profiles between injector-producer pairs. These are then matched to historical performance and used for forecasting on a pattern and field scale.

In the workflow, multiple patterns are analyzed simultaneously. The analysis comprises the following aspects: (1) Gross Rate Analysis: an iterative scheme is developed to calculate allocation factors between injector-producer pairs that match the measured injection and production history; (2) Swept Pore Volume Analysis: injector-producer connections are assigned pore volumes and properties such as heterogeneity and initial recovery factor at the start of the forecast period; (3) Oil Response Analysis: type curves are used to calculate oil production from each injector-producer connection to match historical oil production and predict future oil response under different development scenarios.

The workflow was first verified against synthetic finite-difference models and a good match of gross rates and oil profiles was obtained. The allocation factors and pore volumes assigned to injector-producer pairs were comparable to the values obtained from streamline calculations and simulated tracer data. The workflow was subsequently applied to an actual brownfield development with 24 waterflood patterns, 46 polymer patterns and 2 alkali-surfactant-polymer (ASP) patterns. The historical performance of individual producers and patterns were well captured. Finally, the incremental recovery obtained from EOR was evaluated by comparing the performance forecast of existing EOR activity (NFA) with the waterflood baseline.

The workflow produces comparable if not more accurate results than alternative methods in a fraction of the time. In addition, it provides good physical insights into the origin of the produced oil, making it especially suited for development optimization studies. The established workflow also sets the foundation for a generalized approach that can be applied for development and reservoir management of various chemical EOR applications.
Data Science for Water Cut Analysis System Utilizing ESP Sensor Data – Prototype, Pilot, and Its Potential Impact
Authors: Akbar Bibi Hussain , Sumarto Brahmantiyo Aji , Nugroho Bogi Haryo , Arief Mohammad Joenaedy , Al-Aradi Huda Jassim , Achmad Pajar Rachman , Hakim Zainal
Published: October 2022

Coming up with reliable water cut analysis and estimation has been challenging. An increase in water cut reduces oil production to no oil or is no longer economical. Water cut from the Portable Gas Oil Ratio (PGOR) test, while considered the most accurate is not sufficient to provide continuous water cut monitoring. Wells with Electrical Submersible Pump (ESP) have sensor reading acquired in real-time which can be utilized with supporting data to estimate water cut, fill the gap between PGOR tests and come up with continuous readings. This is conceptualized on spreadsheets and manually gathered the data from multiple sources. It may take hours to work on a single well and days for multiple wells with a complete cycle may take around 3-4 months. During the project, the prototype was built based on the solution design to provide seamless, advanced, and efficient water cut estimation through scalable data science-driven approach, data quality assessment, and improvement to ensure the data meeting the requirements, and a pilot was performed on the prototype. The prototype showed excellent results compare to the conventional approach with simply a few clicks process that yielded the results in seconds. It delivered pleasing water cut model results and disclosed major business benefits. Potential impact through transforming the prototype into full implementation includes time-saving – running time to 5400 times faster and cost saving with potential oil that can be minimized by approximately 465,000 BBLS (observed on 9 wells between Oct-2019 to Dec-2021).