bluuebunny/crossref_metadata_2025 huggingface dataset:
Identification of Key Wells for Waterflood Optimization Considering Geologic Uncertainty
Authors: Sen Deepthi , Chen Honquan
Published: February 2022

Streamline-based rate optimization is an iterative process, requiring several simulation runs. Though efficient for a single realization, it can be prohibitively expensive while considering geologic uncertainty involving large number of realizations. Moreover, the optimal schedule based on one individual geologic model may not necessarily result in favorable outcomes for the real field due to the geologic inconsistencies between the real field and the model. This paper proposes a workflow that integrates unsupervised machine learning and streamline techniques to select representative geologic realizations based on their flow features. The proposed approach generates a distribution of optimal rates for each well, and this in turn is used to identify key wells for which we may advise rate change with high certainty.

Given a set of historical production and injection data, firstly, an ensemble of Nreal history-matched geologic realizations is generated using ensemble-smoother with multiple data assimilation (ESMDA). Subsequently, the streamline time-of-flight (TOF) and principal component analysis (PCA) are used to extract the flow feature of all realizations, based on which k-means clustering algorithm generates a subset of Nclust realizations representing the whole ensemble. The rate optimization is performed on each of the representative realizations using a streamline-based rate optimization algorithm that seeks to maximize the oil production during the optimization period. The distribution of optimal schedules obtained by optimizing the representative realizations is shown to be in high correspondence with that obtained by optimizing the full ensemble. Using the optimal schedule distribution, the key wells are identified, for which rate change is advised with high certainty. The workflow is tested on a synthetic 2D reservoir model as well as a 3D field-scale benchmark reservoir model (SAIGUP model).

The novelty of this work is the combination of the streamline-extracted flow features and unsupervised machine learning methods to formulate an efficient workflow for uncertainty analysis of optimal well schedules. The proposed approach ensures quality and rigor of uncertainty analysis with significantly reduced number of geologic realizations and thus, makes the approach well-suited for large scale field applications.
Qualifying Novel, Risk Reducing and Efficient Disruptive Definitive Dynamic Surveys in Middle Eastern Fields
Authors: Oliveira Victor , Dossary Abdullah , Osman Ahmed , Elsadig Mohamed
Published: February 2022

Over the past 40 years, the oil and gas industry standard for performing wellbore surveys with measurements-while-drilling (MWD) tools was by six-axis stationary surveys. These surveys required a sequence of events involving releasing drillstring torque and pressure and providing zero motion while making and sending downhole survey measurements. This procedure involves drilling risks, delivers reduced drilling efficiency and increases the risk of differential sticking in depleted reservoirs.

As a leader in modernizing the drilling industry, a major operator has worked with a major directional service provider to pioneer a new MWD surveying technology that delivers definitive surveys while drilling and without any need for stationary time or the risks associated with it. The breakthrough technology is expected to change the previous 40 years of industry practice with a new MWD surveying technology known as definitive dynamic surveys (DDS) technology. The technology will deliver definitive surveys while on bottom drilling with full parameters and complete data quality control. This technology will have the benefit of eliminating the current time needed for stationary surveys, reducing the differential sticking risks, increasing surveying frequency for better wellbore positions and providing improved wellbore tortuosity understanding to manage microdoglegs for improved wellbore quality and completion operations integrity.

As a main field tester of this technology, over 30 test runs were made within Middle East fields. As the technology matured, three operational runs have been recently conducted with the aim of comparing and qualifying them compared to industry standard gyro and MWD surveys. The operations were conducted in different well profiles including a vertical, a highly deviated, and a horizontal well. The results have shown an excellent match with less than 0.3° in inclination and 0.5° in azimuth and well within the bounds of their respective error models. The data also showed the improvement in well positioning and drilling efficiency using this technology. Finally, the technology has shown around 50% reduction in connection time on the trial wells.

These results have given the required confidence for the technology, gaining the benefits this disruptive technology brings to the drilling process. This technology is expected to change the industry norm of wellbore surveying and produce a disruptive change in the drilling and well placement operations.
How Data Product and Mesh Thinking can Accelerate Your Digital Transformation Strategy and Adoption of the OSDU Data Platform
Authors: Quinn Paul
Published: February 2022

The Drive for Digital Transformation

Today's Energy Industry has a multitude of challenges – from ensuring that existing assets are used to their maximum potential to incorporating new ways of working and New Energy sources whilst adapting to and adopting constantly changing regulatory and environmental regulatory concerns. This is on top of the traditionally strong concerns of operating at scale, safety and the use (and reuse) of assets that have been established over a significant period of time. This is in the midst of a transformation happening across all of industry. The new industrial revolution in data, analytics and AI has meant that there is both significant opportunities and pressure to address these challenges and concerns using new and novel, tools, technologies and techniques. From a company perspective this means that there may be a focus within these new areas to attempt to deliver increased efficiency, new information or increased value. However, underpinning this there must be a focus on ensuring that foundational capabilities are in place to provide the safe, reliable and agile environment in which this digital transformation can occur.

There are a number of ways of thinking about data and its use within an organisation that may make the goals and expectations of a digital transformation programme more achievable. This is both based on emerging and established best practises for using data within the IT development community, which focus on how data must be protected and developed as a valuable and, crucially, usable asset within a company.

Within systems projects there is also the approach of reusing proven, field tested systems and components (COTS). Through the reuse of these Energy Industry building blocks, operators can focus instead on more company-specific value-adding digitalisation activities and attempt to move up this value chain by looking towards efforts that enable innovation or provide competitive advantage instead of duplicating effort where there exists coordination (or a de facto standard) across the industry.

The OSDU Data Platform cross Energy Industry collaborative initiative to deliver foundational data capabilities and also the provision of common data definitions, ways of working and common functionality on top that data for multiple disparate domains in the industry. This will allow operators, system integrators, independent software vendors, and application developers to work with data in a consistent manner and give this ecosystem the ability to build value adding tools, platforms and apps against. The OSDU Data Platform can therefore deliver key capabilities within a digital transformation roadmap and allow operators to focus on differentiating capabilities. This paper explains, from a high level, how the OSDU Data Platform can be used in conjunction with IT best practices to accelerate digital transformation.
Role of Lean Principles and 5S Programs in Increasing Maintenance Productivity
Authors: Al-Hussain Abdullah , Al-Ahmed Hussain
Published: February 2022

Lean is a methodology that concentrates on monitoring a process or a system, analyzing it, minimizing waste within the system, and increasing productivity simultaneously. On the other hand, 5S, which is an abbreviation for Sort, Set-In-Order, Shine, Standardize, Sustain, is a principle utilized to eliminate Process wastes which may include: wasted time, wasted space, and wasted inventory. The scope of this paper is to showcase the importance of employees’ contribution in continuous improvement initiatives and culture of capitalizing on the benefit of lessons learnt and knowledge sharing.

The program began with educating maintenance team about Lean Principles, 5S Programs, DMAIC (Define, Measure, Analyze, Improve and Control) methodology and their importance. Then, sessions of brainstorming and data collection were conducted. In addition, employees were encouraged to use A3 papers to draft a comparison between current state and future state of any process, step, or a procedure which they think can be performed in a better, faster, safer, and more efficient manner. Next, a weekly continuous improvement meeting was held by quality committee which consisted of members from maintenance, quality & reliability, and management teams to review each improvement idea and take a proper action.

The positive impact of Lean, 5S and DMAIC have been proved working and helped drilling business unit to exploit cost saving opportunities, maintain a perfect record of service quality with client, and improve maintenance productivity. This includes 100% client satisfaction and operating efficiency, 50% reduction in equipment turnaround time, over 100% increase in number of equipment maintained per month and decrease in overtime man-hours by 90%. These results were achieved after close monitoring and controlling of the overall process conducted for over 52 weeks (From Q3 2020 to Q3 2021) and more than 60 improvement ideas implemented. Improvement ideas were received, reviewed, analyzed, further enhanced, and immediately implemented to ensure the end results are obtained. The improvement ideas and lessons learnt register was built to document, give credit, and protect intellectual property of the idea owner and recognize top contributors to the register.

This success story of performance elevation, cost reduction, process optimization and best practices implementation can be cascaded to other departments and companies delivering products and services to the petroleum industry.
AI Driven Approach to Predict Sonic Response Utilizing Typical Formation Evaluation Logs
Authors: Alghamdi Muataz
Published: February 2022

Artificial intelligence is used to capitalize on commonly run well logs to build and train an artificial neural network model to predict the sonic log curve. The dataset used to develop the model is made up of a total of 50 well logs for an oilfield that is located in the eastern part of US. It includes actual recorded sonic logs, which allows a comparison between model driven results and actual sonic curves to evaluate accuracy.

Commonly run logs are used to train prediction models. Log selection targets meaningful petrophysical correlations to sonic properties. Well logs were preprocessed for data cleanup and scaling. After that, the data was broken down to geologically continuous chunks, and splitted to training, validation, and testing subsets. Artificial neuronal network models that use different combinations of neural network layers, hyperparameters, optimizers, and architectures to train the model are investigated to decide on the best approach to construct the predictive model. Automated hyperparameters tuning is employed to further enhance the model accuracy.

After evaluation, a total of four models are selected to train. The resulted sonic logs produced by the models are assessed for accuracy, and are visually plotted and compared to actual logs. The models are ranked based on their accuracy and ability to detect geological features. The models show variations in prediction capabilities. They show that models that are built based on recurrent neural network performed the best. In addition, introducing convolutional neural layers to the models further enhanced accuracy. It is observed that the models are doing a better job of predicting when there is a clear change in values, and are less effective when actual values rate of change is low. Overall, the model that is built employing Gated Recurrent Unit combined with convolutional layers performed the best. In comparison, models that are purely built on dense neural network structure didn't yield good results. Also, it is proven that automated hyperparameter functions are effective in improving models’ accuracy by tuning of parameters through several iterations.

The paper exhibits the effectiveness of utilizing evolving AI techniques to capitalize on expanding existing formation evaluation methods to extract more data from commonly run well logs. In addition, developing a model to predict sonic response negates the need to run actual sonic logs, which saves cost and operational time. Also, AI derived data from previously acquired logs in the wells of interest can help in calibration of models in applications such as geomechanics and wellbore stability studies. This approach can be potentially used for real-time predications without running sonic tools in wells.
A Non-Intrusive Method Using Positively Induced Pressure Waves to Track Moving Objects Within Pipelines and Wellbores
Authors: Newman Stephen , Jack Graham , Savenkova Anna
Published: February 2022

A field proven method is presented for live location tracking of objects within pipelines and wellbores. Tracking is based on analysis of induced pressure waves within the conduit. The method can be used, for example, to track the location of a pipeline pig during a pigging campaign. Data such as pig position, velocity and estimated time of arrival can be calculated. The method can also be used to confirm an object has not become stuck.

A high sensitivity pressure recorder is attached to the pipeline or wellbore of interest. A pressure wave is then formed by releasing a quantity of high pressure gas or liquid into the pipe. The wave then travels at the speed of sound along the pipe and reflects off any object forming an obstruction. Once reflected the pressure wave returns to the pressure recorder. Through analysis of the time this pressure wave takes to travel along the pipeline and return to the data recorded, the distance to the object can be calculated. The process is repeated to provide live tracking.

The method discussed has recently been successfully used to track pipeline pig location on a large diameter pipeline project in the middle east. The pipeline had a stuck pig from recent commissioning activities. The location of the pig was unknown. It was also unknown if the pig was stuck or still moving slowly.

Pressure logging instrumentation was mobilized to site and from the initial surveys performed, analysis of the recorded pressure data confirmed the location of the pig. Subsequent surveys and analysis a short time later confirmed the pig was not moving. A remediation plan was put in place to retrieve the pig and pressure wave technology was used to track the location of the pig during its recovery.

During the operation it was found and validated that it was possible to track the location of the pig to within 100m. Through successive testing, the live pig velocity was calculated and from this an estimated time of pig arrival. Throughout the entire pigging operation, the pig location was tracked. The pig arrived in the pig receiver within minutes of the predicted arrival time.

Live tracking provided confidence to the pipeline operator that the remediation plan was going to be successful. Accurately understanding the pig arrival time allowed optimization of subsequent commissioning activities.

The proposed method allows tracking from one end of pipeline. Sensors are not required along the route and a transmitter system is not required on the pig. The method can be applied to any object in a pipeline or wellbore and offers savings to operators. Information collected can also be used to better plan subsequent activities and contingencies creating savings on overall project schedule.
Multi-Scale Investigations on the Geometries of Hydraulic Fractures in Conglomerate Reservoirs
Authors: Liang Haipeng , Tang Huiying , Qin Jianhua , Li Yang , Zhou Xianmin , Zhang Liehui
Published: February 2022

Currently, the research on hydraulic fracture geometries is mainly focused on tight sandstone and shale. The investigations on the conglomerate tight reservoirs, e.g., Mahu Oilfield in Junggar Basin, China, is still lacking due to its uniqueness and late discovery time. The strong heterogeneity and the existence of gravels in conglomerate tight reservoirs put great challenges on the study of hydraulic fracture geometries. In this paper, a whole field cohesive zone model in finite element method is used to model the fracture nucleation and propagation in rock matrix (sand) and gravels in lab scale. The numerical model is validated against some published experimental results. Based on the analysis of numerical results, a mathematical model for quantitative characterization of fracture growth speed in conglomerate reservoir is proposed. This model is critical to connect the fracture propagation behaviors in lab-scale with the hundreds of meters field-scale hydraulic fractures. For the field scale fracturing simulations, the UFM (unconventional fracture model), which is based on boundary element method, has been widely used. Considering the similarity of crossing behaviors between hydraulic fracture-gravels and hydraulic fracture -natural fractures in conglomerate and shale respectively, a series of natural fractures are used to equivalent the impact of gravels in lab scale in the field scale simulations. The parameters of the equivalent natural fractures are determined according to the propagation model extracted from the lab-scale numerical simulations. The multi-scale research on fracture geometries and methods for field scale fracturing simulations for Mahu conglomerate reservoir could provide important guidance for the future design and optimizations of hydraulic fracturing.
Carbon Footprint Reduction by Utilizing Real Time NIR Spectroscopy for RVP Measurement in Natural Gas Condensate Stabilizers
Authors: Muhammad Moin , Ratajczak Todd , Watson Nathanial , Zhu Jie , Little Paul
Published: February 2022

Objective

Use of near-infrared (NIR) spectroscopy for Reid Vapor Pressure (RVP) measurement has enabled condensate stabilizers at natural gas separation sites to optimize their operation, resulting in significantly lower energy usage, less gas production, more liquid conserved, more on-spec product, and higher profitability. The combination of energy usage optimization and an improved liquid/gas ratio provides a double benefit in both Environmental, Social, and Governance (ESG) criteria and return on investment (ROI). Optimization is achieved by utilizing the 15-second measurement interval of the JP3 Verax NIR on-line analyzer for process control, as compared to manual control. In condensate stabilizers, RVP is reduced by removing light components (C4-: butanes and lighter hydrocarbons) by heating; these are sent to a compressor for vapor recovery. In many instances, the light hydrocarbon gas is flared off when it is uneconomical to transport it for sale. The remaining condensate goes to a reboiler and a cooler before being sent to pipeline. The reboiler heats the liquid fraction before recirculating it to the column; the cooler uses pumped water in a heat exchanger to reduce the stabilized condensate temperature and vapor pressure for storage and transport.

These are energy-intensive processes – the compressors use electricity, the reboiler burns fuel gas, the coolers use electricity and large volumes of water, and waste gas flaring impacts carbon credits and allowances. Optimizing these processes via real-time process control informed by RVP measurement can provide substantial benefits in each energy-consuming step.
Mitigation of Injectivity Loss in Polymer Injector Wells at North Kadi Field of Mehsana
Authors: Gupta Nayan , Chanchlani Kuldeep Laxmanbhai , Jain Pramod Kumar
Published: February 2022

The north sector of the North Kadi field at Mehsana is a brownfield with a primary recovery of only ~20% despite good permeability and active aquifer support due to high mobility contrast, with oil viscosity between ~50 to ~120 cP. Polymer flooding is formulated through 8 injector wells in an inverted spot pattern with 21 producers. The key risk involved is the loss of injectivity in polymer injector wells. A case study of two injector wells demonstrates successful mitigation measures employed for the injectivity improvement.

The partially hydrolyzed polyacrylamide polymer solution is injected into the polymer injector wells. Injector wells lose injectivity over time, making it hard to keep injection pressure below the designed maximum operating pressure. Critical analysis of the trend of injectivity decline is carried to identify the root causes. A structured mechanism for various mitigation options like solvent treatment, oxidizer treatment, acidization, backwash and technical water squeezing, artificial pressure drawdown, and formation bottom cleaning near the wellbore is discussed.

The quality of raw water used for the polymer preparation based on parameters like TSS, turbidity, TDS, and hardness is a key factor in the injectivity loss in the injection wells. In case of rapid decline in injectivity due to poor quality of water with high TSS, turbidity, TDS, and hardness content, solvent squeezing followed by acid stimulation proved optimal. During a gradual rise in injection pressure, while maintaining satisfactory water quality, acid stimulation in combination with oxidizer treatment such as Ammonium Persulphate (APS) proved beneficial. Injectivity maintenance in polymer injector wells has resulted in production gain of approximately 172 tons/day, reducing operational expenses significantly. Monitoring of polymer injector wells is critical, and diagnostic examinations are conducted regularly to assess the severity of the decline.
No More Inefficient Crude Desalting - Breaking Bottleneck with Dual Frequency Technology Lowering Total Cost of Ownership
Authors: Elumalai Prabhu , Sams Gary , Subramani Umanath , Sanghani Pinkesh
Published: February 2022

Historically, the engineering and operations teams in refineries have been constantly challenged to deploy efficient solutions for their crude desalting processes as part of the crude distillation unit (CDU). Inefficient crude oil desalting employing AC technology leads to higher utility consumption and corrosion-related issues with downstream equipment that create multiple bottlenecks while processing opportunity crudes. In addition, these challenges lead to a significant increase in operating expenses due to processing upsets and subsequent downtime.

A major independent crude oil refinery in Asia is processing crude oil in two CDUs utilizing an AC technology desalting system. The total design capacity for the CDU is 206,000 BPD. The first CDU desalting equipment is designed for 150,000 BPD, and the second CDU is designed for 56,000 BPD. Both CDUs were operated in a range of 10 to 30 PTB inlet salinity. However, due to inefficient desalting, less than 60% desalting efficiency was achieved for each train with subsequent low dehydration efficiency. This led to a considerable bottleneck with the processing capacity and much higher chemical consumption, accompanied by frequent upsets and operational issues on downstream equipment.

After a review of the entire desalting operations, the CDU 1 desalter vessel was upgraded to dual frequency technology, and a new dual frequency desalter was installed at the second stage of CDU 2. This change provided a paradigm shift in handling opportunity crude blends in the range of crude density 21 to 28° API with the flexibility of 20 to 100 PTB inlet salinity. After the upgrade, the CDUs achieved a desalting efficiency of more than 90% on each stage and more than 99% on two stages.

This paper examines the project from early engagement through conceptual technology selection phase, engineering design, and project execution leading to a successful startup backed by operational history. Furthermore, the adoption of dual frequency technology over legacy AC technology demonstrates the twin goals of positive economic and environmental stewardship, thereby lowering the total cost of ownership to the customer.

The CDU 1 dual frequency technology retrofit has been in continuous operation since 2019 and performing well within the PTB outlet specifications. The system is running with 40 to 50 % lower utility consumption, both chemical and power savings with reduced downstream corrosion and an increase in uptime reliability.
State of the Art Membrane Nitrogen Technology Enables Remote and Large-Volume Pipeline Leak Testing
Authors: Hella Abdullah , Al-Ajmi Mohamed , Abdelrahman Sherif
Published: February 2022

The paper presents a case study of applying Membrane Nitrogen technology in purging a 600 km long pipeline in Saudi Arabia for pressure testing purposes. The paper will cover the operational advantages and superiority that comes with using Membrane Nitrogen Technology compared to using Cryogenic Liquid Nitrogen. Besides that, potential applications for the technology in remote projects requiring large volumes of Nitrogen will be covered in the paper.

The paper will explain in full detail the Membrane Nitrogen technology along with elaborating how the process works at remote sites. In addition, comprehensive elaboration of several aspects of the technology are discussed; including but not limited to quality of Nitrogen generated, injection rate capacity, injection pressure and the process flow diagram. The paper also examines how this technology eliminates the logistical challenges and ensures maximum efficiency at the job site.
Exploring the Barriers to Implementation of Carbon Capture, Utilisation and Storage in Nigeria
Authors: Betiku Adedola , Okon Bassey Bassey
Published: February 2022

The global economy has increased CCUS technology development programmes to attain its commercial deployment, which is expected to be beneficial for developing countries such as Nigeria. This paper aims to examine the barriers to CCUS implementation in Nigeria by investigating the differences between global CCUS and Nigerian status, evaluating the perspectives of industry and government practitioners on the economic barriers to CCUS implementation, and identifying policy and industry strategies to deepen the adoption of CCUS. Study participants were selected using a purposive sampling technique to explore the opinions of personnel working in three oil-related agencies: Nigerian National Petroleum Corporation, Ministry of Petroleum Resources and Nigerian Liquefied Natural Gas. Information collected from existing literature and related reports on CCUS were critically analysed, whereas data from semi-structured interviews were generated by audio-recording of participants’ responses. These responses were transcribed from audio recordings for each participant and quality controlled by ensuring that transcripts matched the respective responses. Transcripts were analysed using thematic analysis, exploring the research theme using both theory and practice. The theoretical framework utilised PESTEL and SWOT analyses to evaluate the macro environment and the internal and external environment of CCUS implementation in Nigeria. PESTEL analysis showed that CCUS implementation in Nigeria is driven by various regulatory and policy frameworks, lack of adequate capital, public acceptance and infrastructure. Similarly, the SWOT analysis showed that Nigeria has enough coal reserves that could serve as a potential for CCUS implementation. However, Nigeria’s weaknesses include lack of expertise in CCUS technology, inadequate capital for CCUS investment and policy summersaults by successive governments. Nigeria should thus consider the introduction of subsidies to mitigate various barriers and challenges that hinder CCUS implementation, e.g., low tax rate for enterprises involved in CCUS implementation. There is also urgent need to improve funding of CCUS implementation through foreign direct investment or by the equity market. Furthermore, the importance for an enhanced technology to deepen the adoption of CCUS in Nigeria can not be overemphasized as the world moves towards decarbonisation and Net Zero.
Autonomous Well Performance Troubleshooting; A Promising Data-Driven Application
Authors: Abdelrahman Sherif , Al-Ajmi Mohamed , Essam Tarek
Published: February 2022

Well Performance can deteriorate due to several reasons, for example: formation damage, scale buildup, back pressure from other wells, artificial lift issue etc. In this paper we present an application of utilizing machine learning to build a model to articulate and flag deterioration and reason behind it. The model was used to flag problems such as salt and scale build up in the tubing as well as backpressure due to emulsions in the tubing or in topside pipes. The model was capable of monitoring well performance using only the well head parameters
Selection and Evaluation of Ejectors for Flare Gas Recovery and Upstream/Midstream Gas Compression Applications
Authors: Ainge Peter , Al-Khateeb Eyad
Published: February 2022

Historically, Ejectors have been regarded as novel but inefficient devices. For projects requiring a dedicated motive liquid stream (where one was not already freely available), the high liquid flow rate requirements (and therefore high pump power requirements) were prohibitive when compared to equivalent rotating compressors.

In recent years, through its ongoing long-term Product Development Project, Ejector specialists, Transvac, have significantly increased the efficiency of its liquid-driven Ejectors. In some cases, over 50% reduction in pump power requirements has been achieved. Importantly, these improvements mean the new Ejector designs often require less power than traditional compressors.

This paper will explore the latest advancements in Ejector technology and how this has altered the landscape for the selection process of various compressor types for highly challenging duties, such as Flare Gas Recovery and midstream gas compression. In particular, we will see how improvements in liquid-driven Ejectors (Liquid Jet Compressors or LJC's) can offer significant power savings compared to other compressor types.

We will use recent case study/project examples demonstrate how Operators such as Saudi Aramco have already successfully implemented Ejector technology for Flare Gas Recovery and other gas compression applications. The selected projects will demonstrate how Ejectors can be driven by ‘waste energy’, how they can be controlled and other operational considerations. We will also look at how Ejector solutions can operate efficiently using dedicated high-pressure pumps as part of a complete packaged solution.
Pre-Intervention for Multistage Frac Operation: Abrasive Perforation Challenges and Lessons Learnt
Authors: Mezabia Othmane , Belkacemi Ahmed Amir
Published: February 2022

The Plug and Perf technique is the most common application used in completions or horizontal wells that require multistage hydraulic fracturing.

Once the horizontal well is drilled, cased, cemented and isolated - two runs of coiled tubing will be required. The first coil tubing run will be to clean up residual cement and the second run to convey the first set of perforating guns to the end of the well or toe. Once the perforating guns are initiated and perforated holes through the casing and cement into the formation, fluids can now be pumped into the formation. This injected fluid is required to push the WireLine bottom hole assembly (BHA), containing a frac plug to the target depth.

The use of pressure-activated toe valves or Toe Injection Valve (TIV) in a completion string is yet another innovative approach to completing a horizontal well. This technology eliminates the need for perforating guns prior to a multi-stage hydraulic fracturing (frac) operation. Subsequently, the operator can greatly reduce costs when the need for coiled tubing (CT), wireline (WL), or workover rig (WOR) is no longer needed on location to convey perforating guns.

However, if the completion is not equipped with Toe Injection Valve TIV or when injection rate through it is not adequate for wireline pump-down operations, or the toe valve (TIV) fails to open, in this cases the operator must rely on the conventional methods of perforating in order to achieve injection into the well and begin the frac operation.

The conventional method will negate any cost savings that the TIV was designed to provide.

In this paper will review cost effective solution using a motor BHA and abrasive perforator in tandem to clean-out, perforate make another clean out, test the infectivity and Pump acid if needed all in one run using by-pass abrasive tool.
High Gain, Low-Cost Production Optimization of Brownfield in Sarawak Offshore
Authors: Dasuki Nurul Ain , Chaw Kit Teng , Zamdy Siti Nurdyana , Polycarp Maurice
Published: February 2022

In the quest to unlock extra barrels in this challenging oil and gas environment, operator had decided to pursue low-cost oil gain via surface facilities optimization. It is becoming more important than ever to ensure the production system is managed optimally. This initiative was rolled out to all its brownfield asset located at offshore Sarawak. To achieve this objective, Integrated Network Modelling (INM) was conducted to identify facilities bottleneck and optimization opportunities. A structured workflow was utilized to ensure a thorough assessment prior going into full field implementation. All well models were updated to ensure they are representative of the latest field performance. Upon integrating the subsurface and surface system, the model was calibrated with the latest field parameters. Sensitivities run were carried out to identify production constraints and optimization options which include choke size optimization, well bean-up opportunities, separator pressure optimization and system backpressure evaluation. The options were then prioritized based on implementation cost and economic value. Outcome of this study concludes a total potential gain of 5.81 KBOPD from eight fields. This paper presents the overall strategy in finding opportunities from surface facilities optimization via INM.
Integrated Approach to Solving Sand Issues at Onshore Terminal
Authors: M. Johar Juhaida , Myo Thant Maung Maung , Tuan Mahmud Tuan M. Yusoff , T. Aziz Tengku Zulfadzly , Che Daud M. Faizal
Published: February 2022

Lately, one of the terminals in Peninsular Malaysia receives hydrocarbon with fine sand content from multiple offshore feeders. Majority of the sand particles size is below 16 µm with the presence of mercury and TENORM. Sand accumulates, causes erosion, and clogs the equipment and instrumentation devices installed. It has also impacted gas and condensate export specifications. The paper presents a techno-economic evaluation of sand management solution for the terminal to meet an export specification of maximum 5 µm sand particle size both in gas and condensate stream.

The evaluation started with sand data establishment such as sand particle size distribution and sand concentration via online sand sampling. Sand Transport and Erosion Modelling Study was conducted using combination of PETRONAS owned Sand Suite Technology and commercial software for quantitative evaluation of sand mapping, deposition, and erosion within the facility. A total of eleven (11) proven sand technologies at various locations were screened and four (4) technologies were selected as a basis to develop solution options. Via Concept Select Methodology, the evaluations conducted based on Risk Ranking Criteria, CAPEX, OPEX and Schedule. The estimated performance for the selected option was quantified and sand disposal strategy was determined.

An In-Vessel Cyclonic Device is proposed in the existing Condensate Separators and Cartridge Filter at upstream of the Condensate Metering. Gas System will be provided with new Cartridge Filters. These technologies are commercially proven to meet an export specification of 5µm. The proven technology for this application does not differ much for the last few years. New technologies are recommended to be deployed in the terminal and the performance of these technologies are quantified and compared. As the terminal was not originally designed to receive sand, sampling improvement is also proposed to collect more sand data prior to next engineering phase and to measure performance of the proposed technologies.

The results from this study show that current technology could provide a solution to manage fine sand both in gas and condensate. PETRONAS in-house technologies are compared and could be a better option in reducing OPEX and operators’ exposure to hazardous components thus minimizing the impact of transported fine sand on surface equipment in general.
Digital Solution to Extend the Life of Wells with Continuous Corrosion Monitoring Based on Machine Learning Algorithms
Authors: Dallag Mohammed , Bawazir Mustafa , Al-Ali Ali
Published: February 2022

Well integrity in the oilfield is one of the challenges that petroleum engineers face, as they seek to monitor well corrosion in the field to optimize well performance. Most of these fields can be categorized as brownfields, with some of the wells considered aged and have expected integrity issues. To achieve sustainable production targets with cost-effective and safe operations from these fields requires a close monitoring of the integrity of all elements involved in the production chain. Addressing these challenges requires the engineers to coordinate and analyze several data elements, including casedhole, openhole, reservoir, well, and production data from multiple sources. Another challenge is to create and automate a corrosion workflow that saves the engineers’ time and improves efficiency.

In this paper, we introduce an innovative workflow that uses the historical corrosion data while integrating the multiple production and reservoir variables. The innovative approach uses machine learning (ML) algorithms to provide a powerful tool for workover (W/O) candidate selection and for optimizing the corrosion evaluation frequency, which are required in different areas of the fields. Different ML methods (random forest classification and neural net) were applied on training data. Different models were created, and the best model will be used. This offered key insights on the rate of corrosion and corrosion patterns. Further, the developed workflow was designed to be self-sustaining and acting as a surveillance tool for monitoring the integrity of the wells.

The first step of the workflow was to start with organizing and auditing the available corrosion data, followed by a review and analysis of existing openhole, casedhole, production, and reservoir engineering data. This approach led us to understand the extent and severity of corrosion in terms of the corrosion rate and the corrosion index. The corrosion logs were digitally interpreted depth-wise in order to explore the maximum metal loss for each interval. New animated conformance corrosion maps were created.

The successful diagnosis through data analytics in a modern integrated software platform will assist in corrosion monitoring and decision-making. The multiple corrosion maps can be animated to visualize the current corrosion profile and predict the corrosion over time, in addition to ranking the wells for W/O candidate selection.
Optimizing Carbonate Acid Stimulation by Minimizing Acid Injection Volume with Selective Treatment Placement
Authors: Sidaoui Ziad , Abbad Mustapha
Published: February 2022

In carbonate acidizing, highly conductive wormholes are created. The process of wormhole formation comprises two major periods: induction and wormholing. The induction period is the time from the first injection of the stimulation fluid to wormhole initiation. The volume of stimulation fluid injected during the induction phase can be more than 30% of the total volume required for the stimulation operation. Minimizing the induction period can significantly reduce the cost and time of matrix acidizing operations.

Several series of core-flow experiments are conducted under the same experimental conditions, namely temperature, pressure and flow rate to investigate the effects of changes made to the geometry of the injection face of the core during acid injection. Induced holes, sometimes called notches, of various depths and locations were created into the injection face of Indiana limestone cores to evaluate their impact on the wormholing with 15% wt. HCl. The pore volume to breakthrough (PVBT) of injected acid is obtained with the notched cores are compared with ones recorded with a regular plain core (baseline).

The experimental results show that inducing hole in the core can significantly reduce the PVBT of injected acid compared to regular cores. The depth and location of the notch both affect the volume of injected acid as well as the optimal flow rate at which the breackthrough in achived. Shallower notches induced in an optimal location can save about 25% volume of the injected acid while deeper ones can help to reduce the injected acid up to 50%.

Moreover, notches can localize the wormhole initiation point. Based on several repeated experimental results, the creation of notch prior to acid injection can optimize a matrix acidizing treatment by reducing the wornmhole induction period and therefore reducing the volume of acid required to achieve equivalent stimulation performance. It also enables more selective treatment placement.

The creation of notches in the formation method has been applied to hydraulic fracturing because it generates weak points and reduces the pressure required to fracture the formation, Kayamov et al. 2019, Aidagulov et al. 2016, and 2015. However, this proposed method is the first application in matrix acidizing treatments that demonstrates the impact of face geometry on wormhole generation.
Enzymes Breakers for Guar and Derivatized Guar Fluid Systems in High Pressure High Temperature Formations
Authors: Oussoltsev Dmitri , Ward Brian , Tjon-Joe-Pin Robert
Published: February 2022

Latest biotechnological developments have provided for enzymes technologies specifically for neutral to high pH crosslinked fluid systems designed for HPHT (High Temperature High Pressure) formations. The following paper content describes a temperature activated High Temperature (HT) enzyme breaker system successfully tested for guar and guar derivative stimulation fluids at 130° to 315° F temperature and 5-12 pH ranges. The enzyme HT breaker demonstrated significant improvements in proppant pack retained conductivity in multiple laboratory tests and confirmed by the results of case studies in HPHT wells. Industry standard tests were conducted in 3 different independent laboratories in North America and the Middle East. The overall goal was to evaluate and compare the effectiveness of standard oxidizers vs the newly developed HT Enzyme systems in reducing polymeric damage in the proppant pack. Conductivity damage is created by unbroken gel residue in the proppant pack and the dynamically formed filtercake on formation faces. The Retained Conductivity test temperatures ranged from 180-315°F. This study covers the impact on stimulation fluid viscosity and time for degradation at different temperatures.

The laboratories tests demonstrated significant improvement, in the range of 83-98%, for retained conductivity in natural sand and ISP (Intermediate Strength Proppant) proppant packs when using the newly developed HT enzyme breakers. The optimum level of pH and breaker concentration were identified for rapid viscosity degradation – polymer fluid breaking. An engineering guideline was developed for HT enzyme breaker system utilization for HPHT formations. Virtually for all tests "broken" fluid viscosity was consistently less than viscosity for linear polymer system, and normally was in the range of the smallest measurable value for industry standard HPHT rheometers. The HT enzyme breaker system confirmed efficiency for high pH borate-crosslinked polymer systems designed for HPHT wells.

Enzymes have been used for over 50 years as breakers. However, due to fact that these proteins are considered to be pH and temperature sensitive, utilization of enzymes breakers was limited. This new HT enzyme breaker system increases the application range for proppant fracturing in HPHT formations.
Production Excellence Program Enhances Operation Efficiency
Authors: Florez Fabian , Calderon Diego , Kartoatmodjo Gayatri , Fendt Andrew , Wilson Gregor
Published: February 2022

Many IOC and NOC organizations have and continue to be face with the challenge of establishing a corporate standard for measuring production performance across their producing assets. The difficulty with this challgenge comes from reporting localized production, managing production shortfalls, and identifying opportunities to increase production. These are three critical elements of production excellence or production performance programs.

This paper presents a solution for this challenge. This novel solution uses the choke model or limit diagram to integrate existing portions of the production performance framework; i. e., shortfall production management, opportunity identification workshops, and well potential calculations. The challenge is to duplicate these elements in a standard way across 12 active producing assets at different geographical locations, with diverse operating cultures, hydrocarbon types, contractual frameworks, and engineering criteria.

Within three years all assets were sharing the same basis for Production Excellence program (Px) with strict reporting discipling enabled by common corporate system. During the same period the overall production efficiency increase by 3% adding 1.1 MMBOE into the tanks.

In addition to the production baseline sustainability, other major benefits included the standardization of oil production loss classification and production opportunities identification workshop to keep the discipline of identifying production potential to reflect the everchanging field conditions.

This paper will present the integration of the Px program as the main endevoar to make it a portion of the operating culture and the proposed method to capture and share the performance gains. Additionally, a tremendous effort was made to build some of the elements directly into the production data management systems in the local operating assets to enable the corporate reporting system to read any source of data. These data are then used as a business intelligence application reporting accessible via smart and interactive dashboards.