bluuebunny/crossref_metadata_2025 huggingface dataset:
Stable Isotopic Variability in Individual Benthic Foraminifera from the Continental Shelf of Tropical Brazil
Authors: Billups Katharina , Eichler Patrícia Pinheiro Beck , Ravelo Christina , do Nascimento Luzia Liniane , Vital Helenice , Gomes Moab Praxedes
Published: October 2022

We analyzed nine benthic foraminiferal species from the Açu Reef belonging to the orders Rotaliida and Miliolida, symbiont-bearing (Rotaliida: Amphistegina gibbosa, Heterostegina depressa; Miliolida: Peneroplis carinatus, Archaias angulatus, Amphisorus hemprichii, and Archaias compressus) and symbiont-barren (Rotaliida: Buccella peruviana, Pseudononion atlanticum; Miliolida: Quinqueloculina lamarckiana). Stable isotopes measured on individual tests display a large intraspecific variability (δ18O: ∼1–1.5‰; δ13C: ∼2–3.5‰) that is not associated with site location, sampling season, or water depth. Positive correlation between δ13C and δ18O values is significant in three of the species (A. gibbosa, B. peruviana, and Q. lamarckiana), with a regression slope similar to other marine calcifiers (∼2‰ δ13C/‰ δ18O), perhaps related to the carbonate chemistry of the calcifying fluid. With the exception of A. gibbosa, offsets from δ18O equilibrium, when distinct, tend to be positive. Offsets from δ13C of ΣCO2 of sea water are negative for two of the rotaliids (A. gibbosa and H. depressa) and positive for three of the miliolids (P. carinatus, A. angulatus, A. hemprichii), with non-symbiont-bearing species of both orders being close to the sea water values (∼ 1.3–2‰). These δ13C differences are consistent with calcification pathways of rotaliids versus miliolids, with the former drawing carbon from an internal pool and the latter from ambient seawater. Our study contributes a large data set that illustrates the importance of vital and abiotic effects on the stable isotopic composition of large benthic foraminifera in a tropical continental shelf, limiting their applicability as paleoenvironmental tracers.
Probabilistic Approach Guides Field Development Plan in Niger Delta
Authors: Carpenter Chris
Published: October 2022

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This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper SPE 207146, “Conceptual Field Development Plan for X Field,” by Khadijah Ibrahim, SPE, Petrus Nzerem, and Ayuba Salihu, SPE, Nile University of Nigeria, et al. The paper has not been peer reviewed.

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The development plan of a new oil field discovered in a remote offshore environment in the Niger Delta was evaluated. Because the oil in place was uncertain, a probabilistic approach was used to estimate the stock-tank oil originally in place (STOOIP) using low, base, and high cases. The base model is recommended for further implementation. The quantity of oil produced is estimated at 15,000 STB/D, which will require a separator that has the capacity of holding a liquid rate of approximately 20,000 STB/D. The authors find that this developmental plan is cost-effective.

Introduction

Field X is offshore Nigeria in water depths of 330 ft. The field has an uncertain oil in place, with a possibility of low, base, and high cases. The field reservoir information is available from the exploration and seismic well data provided. The field size (i.e., STOOIP) is estimated at 95 million (low), 145 million (base), and 300 million (high) STB, with an irreducible water saturation of 22%. The reservoir depth is 7,400 ft true vertical depth subsea (TVDSS), with a net pay thickness of 45 ft. The aquifer supporting the reservoir has a strength of 9, with a permeability of 200 md and a porosity of 18%. Generally, the reservoir has permeability and compressibility of the rock formation obtained from the log results of 250 md and 3.5×10–6 psi–1. The reservoir pressure is measured to be 3,400 psia.

The field development plan will incorporate production forecasts from the target date of first production, 1 January 2023, through 1 January 2038, for a 15-year field life. The complete paper presents the field development strategies and economic analysis of different well models to evaluate the most-efficient modeling profile for the new field.

Methodology

Well-Modeling Profile and Performance Analysis.

It is assumed that the field will be produced using a platform with a wellhead reference depth of 20 ft above the rotary kelly bushing. The well is assumed to be a vertical well with no deviation. The skin value is estimated to be 1, thereby having a slight effect on the productivity index. Pressure/volume/temperature (PVT) data were available for the oil in place. Using commercial software, the fluid parameters for bubblepoint pressure, oil volume factor, and oil viscosity were matched in the PVT analysis at a reservoir temperature of 170°F and a pressure of 3,400 psia. The measurements of formation volume factor, gas/oil ratio, and oil viscosity at this pressure were used to provide a single match point for the generation of PVT data.
Legacy Gulf of Mexico Oil and Gas Facilities Hold Promise for Role in Blue Economy
Authors: Carpenter Chris
Published: October 2022

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This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper OTC 31940, “Repurposing Gulf of Mexico Oil and Gas Facilities for the Blue Economy,” by Roy Robinson, SPE, Excipio Energy; Georg Englemann, Diamond Infrastructure Development; and Kent Saterlee, Gulf Offshore Research Institute. The paper has not been peer reviewed.

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This synopsis presents portions of the results of a Department of Energy (DOE) study of the potential for repurposing legacy oil and gas facilities in the Gulf of Mexico (GOM) for uses in a blue economy. The study was limited and was designed to summarize practical options for repurposing. The conclusions list those areas in which further modeling or studies are warranted, with the objective of building an integrated modeling tool to assist companies, government agencies, and nongovernmental organizations in assessing benefits and risks of repurposing facilities.

Scope Limits of the Repurposing Study

The term “blue economy” is defined by the World Bank as a sustainable use of ocean resources for economic growth, improved livelihoods and jobs, and ocean ecosystem health. The study upon which the paper is based was confined to the repurposing of oil and gas facilities in the GOM, specifically platforms, wells, pipelines, and rights of way. Producing, idle, and abandoned assets were considered. The objective was to explore how leveraging these existing facilities can reduce the carbon load of offshore oil and gas production, speed the energy transition by tapping the tremendous energy potential of the ocean, reduce US dependence on imported seafood and minerals, and create secure long-term employment along the Gulf Coast.

Energy Resource Potential and Definition

In 2020, the US National Renewable Energy Laboratory (NREL), at the request of the Bureau of Ocean Energy Management (BOEM), produced a report on the renewable energy potential of the GOM. NREL divides resource assessments into gross and technical potential. “Gross” is intended to be the total available resource. “Technical” is based on NREL’s assessment of how much of the resource could be captured economically using proven technology. Details are included in the complete paper because the NREL/BOEM report has caused some questions to be raised by those reviewing the DOE study. The authors’ commentary on this report is detailed in the complete paper.
Low-Carbon and High-Efficient Heat Provision by High-Temperature Heat Pumps with Subsequent Steam Compression
Authors: Diezinger Stefan , Huettl Christian , Schaefer Jochen , Paul Christian , Lienau Arne
Published: October 2022

Heat is the world's largest energy end use, accounting for almost half of global final energy consumption in 2021 (IEA, 2021). Heat is utilized in various applications across a broad range of industries, including refining, chemicals, pulp and paper, textile manufacturing, district heating systems, buildings, etc.

Large scale, low-temperature heat pumps are a well-established technology and are currently able to achieve temperature levels of up to 100°C. In recent years, demonstration projects involving Siemens Energy and other original equipment manufacturers (OEMs) have shown that temperatures up to 150°C and 4 bar are within reach using modern high-temperature heat pumps. Further progress has been made to extend this range up to 270°C and pressure levels up to 60 barA using subsequent steam compression. Such configurations recently became bid ready in the marketplace.

This paper provides an underlying description of modern electric heat pump technology and will show how it can be used as a low-carbon alternative to traditional heating methods, such as oil- or gas-fired boilers. Several real-world applications will be presented, including one concept at a large integrated chemical complex in Europe, where a high-temperature heat pump and steam compressor are combined to achieve a temperature of 240°C at 19 barA with a coefficient of performance (COP) of 3.
Supplier Performance Management for Successful Project Execution and Adding Value to Supply Chain
Authors: Kashif Muhammad , Al-Rawas Dalya
Published: October 2022

The Supplier Performance Management (SPM) aims to increase compliance and profitability by preventing risks of cost and schedule overruns due to failures in supplier performance. The excellence in Supply Chain is not possible without implementing a robust SPM. Once SPM is in place suppliers' performances can be analysed, tracked, and improved.

This paper provides complete supplier performance measurement criteria for the project execution stage (a key stage of SPM, success of project depends on it). The paper can be considered a base document for supplier performance management in the project execution stage. Supplier performance once implemented in the project execution stage then can be extended to other stages as pre-award and to vendors for material supply.

Supplier performance comprises four processes: measuring supplier performance; analysing performance data; communicating and engaging with the suppliers; and working together to continuously improve.

The supplier evaluation process starts with initiation of performance score event with typical performance measurement elements such as Quality of Work/Services, Execution: Work Performance, and Health, Safety & Environment (HSE). The elements can have different weightages. The evaluation is done by the contract administrator involved with the contractor during the execution stage. The typical evaluation frequency can be annual, or bi-annual but more frequent evaluations can be done depending on nature or critically of project.

This paper highlights the importance of segmentation of suppliers to optimize supplier performance efforts and increase the prospect of value addition. Based on the Kraljic Matrix analysis, suppliers to be divided into at least four segments - Strategic, Single Sourced/OEMs, Managed, and Low level.

Also, the paper proposes the Strategic Supplier Performance Management (SSPM) process for strategic supplier segment to add quick value to supply chain. SSPM in fact is the application of the Pareto Principle and works by constituting a task force of all concerned stakeholders to formulate smart KPIs to add value.
People Development - Holistic Approach to Leadership & Development
Authors: Salmon Duncan , Dick Simon , Zhupikov Yuriy
Published: October 2022

In 2020 the Australian Institute of Management conducted a Leadership Survey and the "most important finding was that poor leadership is a major contributing factor to employee attrition."

"75.55 % of respondents stated that they had left an organisation in their last three roles because of the leadership team, their direct manager, or a combination of both. Nearly half (42.32%) had left more than one of their previous roles."

We can clearly see that "poor leadership will simply not be tolerated by employees, and this is a rising trend."
VOC Recovery System for Crude Oil Tanker Loading
Authors: Kamel Merhane , Al Shehhi Khalid
Published: October 2022

During offshore and onshore loading of crude oil tankers, huge volumes of valuable Volatile Organic Compounds (VOC) are emitted to the atmosphere maybe up to 330 ton per Very Large Crude Oil Carrier (VLCC). When these emissions are liquified, they will be equal to hundreds of barrels of oil. They are a substantial source of financial loss and destructive environmental impact. The objective of this paper is to introduce a Vapor Recovery System concept which can limit & recover the emissions of VOC up to 90% at the Fujairah Terminal.

All loading and unloading of oil on offshore, on Floating Storage Offloading Unit (FSOs) and Floating Production Storage Offloading (FPSOs), on onshore storage tanks and terminals, and on shuttle tankers contribute to significant emissions of VOCs. It is possible to install Vapor Recovery Unit (VRU) on each of these applications to capture and recover VOCs. There are two generic approaches to VOC recovery, known as ‘Active’ and ‘Passive’ VOC recovery technology. The Active Vapor Recovery Unit VRU systems typically include a compression step followed by condensation, absorption and/or adsorption. The Passive VRU systems use vapor-balanced loading/unloading with VOC as blanket gas for storage vessels.

The VOCs are a combination of Methane and Non-Methane components which evaporate from crude oil and are typically vented into the atmosphere during routine ship loading activities, causing emissions of harmful vapor to the environment. These vapors also represent a fire/explosion hazard. The methodology will be to apply a new concept to limit and recover the VOC emissions during loading of crude oil tankers alongside a Single Point Mooring (SPM). The VOC recovery technology is a unique combination of a modern offshore Supply Vessel (OSV) which considers both hydrocarbon recovery as well as power generation.
Unique Development Plans for UAE Nationals in Dolphin Energy
Authors: Al Maainah Meera Ahmed
Published: October 2022

People Development

Breakthrough Strategies for Staff Development

Objectives/Scope: Please list the objectives and/or scope of the proposed paper. (25-75 words)

The purpose of this paper is to highlight Dolphin Energy's workforce development programs. Striving to develop and support employees is one of the company's top priorities. Hence, multiple strategies have been developed and put in place to focus on employees’ development to meet the company's growth requirements and achieve long-term success.

Methods, Procedures, Process: Briefly explain your overall approach, including your methods, procedures, and process. (75 -100 words)

Dolphin Energy's Talent Acquisition and Learning Department has designed and customized comprehensive development plans to ensure employees have the necessary competencies to perform their work safely, efficiently, and effectively.

The process begins with a thorough analysis of the employee's performance, experience, and education background, in addition to their roles and responsibilities. Following this analysis, a customized career development plan is created to ensure the competency of the employee within their respective role.

The company's current development plans are: Individual Development Plans (IDPs)Career Enhancement Plans (CEPs)Open Development Plans (ODPs)Performance Improvement Plans (PIPs)

Results, Observations, Conclusions: Please describe the results, observations, and conclusions of the proposed paper (100-200 words)

Development plans are tools to develop and prepare employees to excel in their career and hold higher positions in the future. With this in mind, the company is proud that its executive and senior level employees have completed customized development plans, which proved to be successful tools in their career progression.

The company implements high standard development plans to support its employees’ development and growth. These plans also help develop fresh graduate associates and prepare them to be fully qualified job holders by providing them with knowledge, experience and required competencies within a two year time-frame.

Dolphin Energy has succeeded in promoting UAE nationals to senior level positions through multiple career development programs, where currently the majority of UAE nationals hold senior level positions within the organization.

Novel/Additive Information: Please explain how this paper will present novel (new) or additive information to the existing body of literature that can be of benefit t and/or add to the state of knowledge in the petroleum industry. (25-75 words)

As the Oil and Gas industry is always evolving, it's important to maximize employees’ knowledge and development within their respective fields.

This paper will present details and highlight benefits of our development plans, supported with statistics on how successful they are. In addition, this paper will shed light on major milestones and advantages of our career development programs, as well as best practices which may be of interest to other business partners.
Facility Energy Strategy Development and Process Optimization: A Case Study from Saudi Aramco Khurais Facility
Authors: Bajuaifer Hatem A. , Khan Ashiff , Al Zahrani Abdullah A.
Published: October 2022

This paper covers an energy optimization study conducted by Saudi Aramco to maximize energy efficiency and minimize GHG emissions via onion peeling method to analyze the system from outside to inside by segregating the system to three essential layers in Khurais hydrocarbon facility to achieve operational efficiency and environmental sustainability.

This paper is intended to:

Share the optimization strategy and how it can be replicated. Presents the results of this optimization study along with operating modes energy and emissions data and graphical representations. Highlights how this approach enhanced the overall facility operating efficiency.

The onion peeling approach allows to achieve maximum efficiency by conducting sensitivity analysis on each layer's parameters to achieve the optimum operating mode for minimizing power bill (i.e., maximizing power generation), minimizing scope 1 and 2 emissions, minimizing sales gas consumptions.

The aforementioned approach was done based on the following strategies:

Maximize power generation in facility whenever reaching the threshold that makes power generation better than importing from grids in term of GHG emissions and EI. Maximize waste heat recovery for power and steam generations. Minimize recycling in major energy consuming equipment in the facility. Maximize major energy consuming equipment efficiencies through load management optimizations. Follow operating levels concept rather than optimum mode concept by ranking all possible modes in hierarchy and challenge the system to achieve better operating level (i.e., lower level number)

Figure 1 Shows the model's layer and summary

Post-Implementation of the defined strategies and following operating level concept, several initiatives introduced to achieve lower operating levels with energy savings and GHG (scope 1 and 2) reductions realized.

Finally, this study concluded that to achieve better operational mode environmentally and economically, it is recommended to analyze the overall system from outside to inside as multiple layers, to capture opportunities in the system. Such an approach shall be followed after defining the needed strategies, depending on the facility's design, demand and operating conditions.
Multiscale Oil and Gas Methane Emissions Data: From Measurements to Mitigation
Authors: Zavala-Araiza Daniel , Schwietzke Stefan , Hamburg Steven
Published: October 2022

Methane (CH4) is a potent greenhouse gas, responsible for at least a quarter of Today's global warming. Thus, reducing CH4 emissions from global oil and gas infrastructure represents a key opportunity to significantly slow the rate of climate change—with several recent studies highlighting that readily available and cost-effective technologies can reduce a large fraction of current emissions from this industry. Operators have announced ambitious pledges to reduce CH4 emissions from the oil and gas supply chain. For these targets to be effective, it is critical to improve the understanding in terms of how much methane emitted, identify where it is being emitted, and to empirically track progress as mitigation strategies are implemented. Here, we have synthesized results from recent multi-scale scientific studies across geographies (i.e., North America, Europe, Australia), highlighting the role of empirical data in improving emission reporting, and guiding mitigation action. We illustrate how emissions data collected at different spatial and temporal scales can be integrated to provide a clear characterization across the different segments of the oil and gas supply chain. Measurement-based approaches are now being successfully implemented, and the integration and reconciliation of data at different scales can provide useful information to reduce the uncertainty in terms of magnitude and location of emissions. As more operators incorporate these approaches and compile improved emissions data, it will be plausible to improve equipment and system design, perform root cause analysis and reduce the frequency of large emission events. Measurement-based CH4 emissions data is essential to an efficient and effective implementation of CH4 mitigation strategies. This paper highlights how a diversity of robust measurement approaches can be deployed in concert—further identifying mitigation opportunities and tracking changes in emissions over time.
Could Petroleum Sludge be Used to Produce Biomethane as a Renewable Energy Source?
Authors: El Achkar Jean H. , Husain Abrar Ben , Alotaibi Nadeen , Alhaddad Noor , Alamgir Taiyeba , Alshamali Husain , Alshammari Yousef , Almuhanna Mohammad , Albekheet Abdullah , Alenezi Khaled , Alsaba Mortadha T.
Published: October 2022

During the exploration, production, and refining of crude oil, as well as the effluent treatment facilities of refineries, the petroleum sector produces a substantial quantity of sludge. This review offers in-depth insights into the methods used to treat and dispose of petroleum sludge today. It also explores the possibility of valorizing such waste while converting it to a sustainable energy source using anaerobic digestion technology.

Aside from health concerns, the random disposal of untreated petroleum sludge causes land pollution, water pollution, and ecosystem devastation. Consequently, the adequate treatment and disposal of this sludge provide a substantial challenge to the oil and gas sector, which has become a worldwide concern. Various methods used, such as incineration, oxidation, ultrasounds, stabilization, and landfarming will be presented. On another note, this review imparts a new insight into the possibility of generating biomethane from petroleum sludge. It also investigates its anaerobic co-digestion with food waste and other byproducts, promoting the transition toward a circular bioeconomy.

Most conventional sludge treatment methods are unstainable and insufficient to deal with a large amount of generated sludge. Ultrasonic treatment, solvent extraction, and incineration are all expensive processes. Moreover, incineration contributes to air pollution, whereas landfarming and degradation are inefficient and contribute to heavy metals leaching. Considering those disadvantages, creating a greener and more cost-effective approach to securely disposing of these hazardous materials is vital. The bacterial degradation of any substrate without oxygen is known as anaerobic digestion (AD). It is one of the highly efficient systems for recovering bioenergy from small to large sizes. Sludge treatment in anaerobic digesters yields biomethane, a substitute for natural gas, recovered while microorganisms reduce the organic matter in the sludges. However, the sludges have poor anaerobic degradability, and the presence of heavy metals might interfere with anaerobic microorganisms' ability to function. Suitable pretreatment of sludge and its co-digestion with organic wastes such as food waste can be an option to solve the above problems, tackling at the same time the food waste management issues alongside petroleum sludge management.
DMXTM Demonstrator for CO2 Capture: First Results of Experimental Campaign
Authors: Salais Clément , Streicher Christian , Albarracin-Zaidiza David , Carlier Vincent , Bachaud Pierre , Petetin Bernard , Lacroix Maxime , Santos-Moreau Vania
Published: October 2022

3D Project, standing for DMX™ Demonstration Dunkirk, is a European funded project to demonstrate an innovative CO2 capture process at semi-industrial scale: DMX™. The 11 partners of this project gathered their forces to demonstrate the capture process and to study the CCS chain (capture, transport and Storage) allowing to decrease the CO2 emissions from industries (steel mills, refineries, waste-to-energy plants etc).

Objectives/Scope

Carbon capture is due to play a fundamental rote in achieving Net Zero Emissions scenario in 2050. Amine scrubbing is considered nowadays a suitable technology for the sectors with large-fixed CO2 emissions due to its robustness, adaptability, and capability of producing a highly concentrated CO2 stream, suitable to be transported. Four main challenges need to be addressed for the industrial deployment of this technology: process footprint reduction, process energy penalty reduction, solvent and VOC emission limitation and long-term process stability. Some challenges can be addressed through solvent formulation and process configuration. IFPEN has developed a novel solvent and process configuration, the DMX™ process, showing promising results in terms of energy consumption and process stability. This work aims at the demonstration of the DMX™ process by means of a set of experimental campaigns with a demonstration plant treating real gases in the frame of H2020 funded project called 3D (grant agreement n° 838031).

The demonstration plant is installed in the Steel Mill of ArcelorMittal Dunkirk and will absorb CO2 present in the blast furnaces gases. The design and construction of the unit is realized under the supervision of Axens. The demonstration plant is operated by a mixed team from IFPEN and TotalEnergies.

Methods, Procedures, Process

The DMXTM technology is a CO2 chemical absorption process involving a demixing solvent. This process consists in the continuous operation of two sections: 1) the absorption section, in which the CO2 is captured by the lean solvent, and 2) the regeneration section, in which the rich solvent is thermally stripped from the CO2 and recirculated to the absorption section. The particularity of this process is the solvent demixing in the regeneration section. Only the CO2 rich aqueous stream is thermally stripped. In addition, since the regeneration of the solvent can be performed at a relative high temperature (150-160 °C), the DMX process produces a relatively high-pressure CO2 effluent (5-6 bara). Hence, energy and investment cost savings are expected to be obtained.
Comprehensive Design and Diagnostic Approach for Horizontal Completions in Carbonate Environment
Authors: Alobaid Hashem , Khan Abdul Muqtadir , Almulhim Abdulrahman , Hansen Jon , Kabannik Artem
Published: October 2022

The development of tight carbonate reservoirs is moving towards drilling and completing wells with longer laterals. This leads to challenges of longer completion time, high number of fracturing stages, longer interventions, and eventually higher costs. Design cycle implementation is required to devise an engineered strategy to mitigate these challenges.

Lateral landing was conducted based on the cross-section grid consisting of two offset horizontal wells completed with up to 13 fracturing stages. A longer lateral greater than 6,000 ft was drilled compared to 4,000 ft in offset wells to get the production potential. With a strategic design involving engineered chemistry and numerical simulation models, a cluster design was devised to reduce to stages. A mathematical algorithm employing tube wave velocity calculations was used as a diagnostic to ensure diversion success after each stage.

The horizontal lateral was landed traversing the prolific layer. Stage reduction sensitivity simulations were conducted using multiphysics numerical models and novel beta factor workflows to evaluate the extent of stage reduction. The design was extended to plan for five stages only, with increased number of perforation clusters per stage. The reliable diversion chemistry utilized was accompanied by a revised perforation length as dictated by the beta factor workflow. A total of 39 clusters, 2-ft each, were distributed across 6,000 ft with four mechanical isolation plugs. A novel nonintrusive diagnostic model built on mathematical fundamentals of wave travel time was used with a Bayesian statistical approach after each diversion pill placement to ensure fracture fluid entry points and enough coverage in each stage. The high fluid viscosity and operating pumps during the water hammer events resulted in low signal-to-noise ratio in the input data. To overcome these limitations, the water hammer events were processed with a combination of two newly developed algorithms: predictive deconvolution and comb filter, which produced more robust results than the traditional approach. Consequently, the well production was analyzed to show equivalent or higher productivity index compared to the offset laterals with up to two times higher stage count.

The paper presents a unique example in which an experiment was fully engineered from design to evaluation and monitored with reliable diagnostics. This example gives a blueprint for future completion designs.
Digitalization Deployed – Enabling Sustainable Operations with Autonomous Well Control
Authors: Schnabl Helmut , Wimmer Helmut
Published: October 2022

Hydrocarbons have powered economic growth for 150 years, but their emissions are destabilizing the earth's climate. Now that the atmospheric impact of fossil fuels is widely recognized, the sector is under increasing pressure. Policy makers, investors, and society are pressing for change, threatening operators’ license to operate.

Operators have responded with strategic convening and conspicuous investments in innovation and diversification. Yet they have barely begun to address the 4.1 GtCO2e of emissions—almost 10 percent of all anthropogenic greenhouse gas—created every year by their own operations, two-thirds of it from upstream activities.

Technologies to optimize and decarbonize the extraction and production of hydrocarbons already exist and many are economically viable, yet the sector's atmospheric emissions continue to rise.

This paper describes a comprehensive field operating concept that leverages latest technologies — edge computing, data analytics, artificial intelligence (AI) to optimize wells using artificial lifts. Our research and pilot onshore deployments have focused initially on sucker rod pumping (SRP) models because they are a predominant solution for maintaining the productivity of mature, low-pressure wells. We are confident our concept can be applied also to other artificial lift technologies like electric submersible pumps (ESPs) or progressing cavity pumps (PCPs), whether onshore or offshore.

The solution is based on an open and scalable software stack that is capable of performing advanced analytics and softsensing to calculate pump conditions, trigger alerts, and optimize production from wells using artificial lift technology. What's more, with the addition of secure connectivity capabilities, E&P operators of multiple wells, even thousands of them, can gain remote fleet management and enterprise-wide visibility of their artificial lift operations.

Advances in data analytics and sensor technology have opened the door for industrial asset management and optimization across all vertical markets, including oil and gas. Edge computing, data analytics, artificial intelligence (AI), and Internet of Things (IoT) connectivity make it possible to scale up and optimize whole fleets of equipment. The machine learning aspects covered in the pilot implementation made the effective motoring of sucker rods feasible.
Sea Water Injection Department's Unmanned Operation
Authors: AlRammah Ahmed Mustafa , AlFuwaires Saleh Saad , Ghuwainem Fadhel
Published: October 2022

By exploiting forth industrial revolution technologies such as advanced facility data analytics, robotics for inspection, and highspeed network connectivity through fiber optics and industrial wi-fi Saudi Aramco's Sea Water Injection Department was able to disturb conventional operation and transition its UWIP1 to a smartly operated plant. UWIP1 has been transferred from manned operation into unmanned operation.

Aramco's Sea Water Injection Department (SWID) is pioneering industry-leading Digital Transformation (DT) initiatives in advanced facility data analytics, robotics for inspection, and industrial Wi-Fi through an evolving "Integrated Intelligent Operation for Seawater Treatment".

Reservoirs distant from the Gulf used to require significant quantities of saline, non-potable groundwater for injection. To replace most withdrawals from this source, Aramco built in 1979 the Qurayyah Seawater Treatment Plant (QSWP), the world's largest for reservoir pressure maintenance. SWID operates QSWP together with a vast associated pipeline network over a large geographic area covering Ghawar, one of the largest conventional oil fields in the world, as well as Khurais, development of which was the largest crude oil expansion program in oil industry history. Seawater is conveyed to hundreds of injection wells. Operating this system is challenging, with the compound effects of massive throughput, complex network, ageing equipment, corrosive seawater, and the "Great Crew Shift" onboarding young talent in place of experienced ones. To resolve these challenges, SWID tapped into the transformational power of DT technologies across the end-to-end water injection value chain to yield benefits in productivity, sustainability and workforce engagement.
Intelligent Production Optimization Decisions: Prioritizing Production Optimization Through Machine Learning Aided Uplift Quantification
Authors: Sharma Akriti , Chonghyun Ahn Alex , Park Jihoon , Singh Vikash , Rodriguez-Buno Mariana , El-Bakry Amr , Kwong John , Garrison Brett , Gelowitz Tyler
Published: October 2022

Due to complexity and scale, managing and engineering a modern hydrocarbon asset is extremely challenging. The problem becomes more difficult if an asset has thousands of wells to manage because, most of the time, operation resource is limited (either manpower or tool) to achieve production optimization and the amount of information to process during decision making is enormous. Bringing necessary data from multiple different sources and analyzing it in a relatively short period of time to provide actionable/reliable insight to field operators’ and engineers’ is the key to enhance and optimize production performance.

The production optimization best practice is shared amongst field operators and engineers given the geology, reservoir character, and operation strategy which include artificial lift, stimulation, and other workover. This approach has been applied and proven successful mostly in low well count assets by identifying opportunity and providing robust qualitative guidance towards optimum production condition. However, in high well count assets such as unconventional, it is impossible to execute traditional manual approach and it is essential to develop an integrated, flexible, and automated workflow that enhances the efficiency and effectiveness of production operation and achieve "operate-by-priority".

Thus, to have efficient and optimized management of hydrocarbon production from individual well of a high well count asset requires prior, more certain and almost real time knowledge of production rates from the currently or upcoming production wells. Production data, thus, from individual well is very important. Well tests are carried out to obtain production rates and then utilize these rates to provide optimized production decisions and actions. In a well test, a test separator splits the production stream into oil, gas, and water using gravity and support in the management of hydrocarbon production. However, well test are infrequent and doesn't fit the purpose alone with such low frequency for real time surveillance and decision support. Also, well tests are expensive and, hence, it is also not economically viable to do more frequent well tests.
Automated Fluid Rheology Measurement at the Drillsite
Authors: St.Michel Nathan , Xu Jianhui James , Harrist Jonathan , Zhan Guodong David , Aljohar Abdulwahab
Published: October 2022

With the increase of automation and process control requirements, a good real-time grasp of the drilling fluid rheology has repeatedly been flagged as a key requirement. Unfortunately, drilling fluid rheology is still mostly measured manually and reported only twice a day. Fluctuations in fluid composition and rheology due to wellbore/fluid interaction and temperature/shear/solids effects are generally missed.

This paper describes the field implementation and testing of an inline-design pipe rheometer that operates autonomously to continuously measure rheological properties of the drilling fluid in the rig's mud tanks. This data can be used to monitor the stability or indicate changes in these drilling fluids. The system employs a progressive cavity pump to draw drilling fluid from the mud tank and propel it, at varying controlled rates, through two different sizes of pipe. Differential pressure transducers are used to measure the pressure drop over a fixed length in each size of pipe, and this data, along with flow rate, is used to calculate fluid viscosity. All components are installed within a standard ISO shipping container for ease of transport and deployment at the wellsite. It is positioned next to the mud tanks where it continuously samples and measures the drilling fluid.

Field test results of the system are presented. The system was operated autonomously on location in Saudi Arabia for an entire drill stage (3.5 days) of 5-7/8" section for gas drilling. In this section, oil based mud was used and measured by the system. The system was controlled remotely via WiFi connection. During the test period, manual viscosity and density measurements were also taken using the Fann-35 and mud balance methods. Subsequent comparison shows excellent agreement between the automated and manual measurements.
Get Better Data to Drive Production Gains in Tight Gas Reservoir Through an Automated Multiphase Measurement Skid and Production Engineering Workflow Integration
Authors: Theuveny Bertrand Claude , Garay Andrade Carlos , Sanz Vera Julio , Salas Fabian , Pucci Claudio , Castro Alejandro
Published: October 2022

A novel implementation of an economical, self-sustainable and environmentally friendly solution for tight gas field production monitoring in a remote location in Tierra Del Fuego, allows early-stage production measurements necessary in the unconventional reservoir analysis for the field recovery process optimization

The paper demonstrates the gains obtained with the deployment in 12 pads of an automated well testing multiphase metering skids for enhancing the efficiency of production engineering workflows.

The replacement of traditional test separator and test manifold with a fully automated multiport selector valve manifold and a multiphase flowmeter enables a number of new production monitoring and surveillance workflows that can lead to additional production, while lowering both the capital expenditure and the operational costs.

The enhanced data coverage and data quality provides reliable input to advanced engineering processes. The high level of repeatability provided by the multiphase flowmeter establishes a strong foundation for systematic, automatable workflows.

We demonstrate the robustness of the data quality over time with the introduction of new indicators that can be automatically computed and deliver input to more evolved information algorithms.

Beyond the reduction of capital expenditure of 11% and gains over 1100 man-hours per year per installed pads, we enable a number of production insights that translate in better reservoir management and production practices. High quality rate transient analysis can be performed leading to reliable outputs that leads to actionable decisions.

Only few papers demonstrate actual multiphase flowmeter performance in tight gas fields and details how reliable production data is used on a daily basis to enhance reservoir management practices and leads to production optimization.

The definition of new quality indicators on the data streams enables the feed to advanced algorithms and leads to enhanced automation of field management processes.

Finally, we document and estimate the significant reduction on emissions enabled by the deployment of the multiport selector valve manifold and multiphase flowmeter.
Pipeline Integrty Management and the Invent of Analytics for Corrosion Threats
Authors: B. M. Ali M. Nazmi , B. M. Tuselim Ahmad Sirwan , B. Abu Bakar M. Hisham , Kalam Azad M. Fithri Azad B A. , M. Fuzi Nurazzura Binti , B. M. Suhot M. Afiq
Published: October 2022

PETRONAS Pipeline Predictive Analytics for Corrosion (PrAnCorr) is a cutting-edge cloud-based innovation that uses big data from near real-time operating data to predict internal and external corrosions for onshore and offshore pipelines. The technology which made up of multilayer system architecture allows seamless data integration which transform the traditional method of managing pipeline integrity from one where pipelines are typically inspected every 5 years to one in which pipeline corrosion behavior can predicted on near real time, thus reducing dependency of having in line inspection.

The motivation of the development which began in 2019 was derived from significant increasing trends of OPEX spending to control and monitor corrosion development and production losses due to corrosion failures. The formation of multidisciplinary team within PETRONAS had demonstrated proven results for a comprehensive life cycle machine learning system through collaborative efforts.

The system is powered by 2 main processing engines namely iCON (process simulation tool) as a real-time process simulation engine and Machine Learning engine. The prediction utilizes more than 13 operating variables simultaneously generated through integration from various data sources within i-PIMS (PETRONAS Integrated Pipeline Integrity Assurance Solutions) system, capable to perform continuous data ingestion & cleaning which eventually revealed corrosion behavior along the pipelines.

PrAnCorr was successfully deployed in March 2021 as a module in i-PIMS application and has already been used to predict corrosion for various pipeline system i.e., dry gas, multiphase, wet gas, condensate etc. The establishment of PrAnCorr is a significant step forward in the achievement of pipeline integrity performance, especially given that the potential savings derived from optimization of I&M. The positive value creation is estimated for long term application by 20% OPEX reduction over the life cycle. PrAnCorr is prospective for PETRONAS as a future of pipeline integrity solution that spans the company's operations with the capability from obtaining a quality pipeline real-time condition to subsequently performing integrity assessments.
Optimizing Extended Reach CT Intervention Efficiency with Increasingly Complex Operating Environments in Vaca Muerta, Argentina
Authors: Delgado Eduardo , Bivens Eric , Cuevas Stefania , Di Nardo Jose , Lorca Francisco , Beauregard Mario , Lock Benjamin , Godoy Soledad , Salazar Namir
Published: October 2022

Wells in the Vaca Muerta field have consistently hosted an array of technical challenges from downhole conditions in the extended lateral section, including casing collapse or restrictions developed during the hydraulic fracturing phase. With these factors in mind, an initiative was made to implement key operational parameters to improve efficiency during Coiled Tubing (CT) operations without sacrificing (Health, Safety, and Environment) HSE or (Service Quality) SQ during the completion life cycle associated with unconventional activities.

Operational optimizations based on ongoing diagnostic, design and delivery of CT well interventions are shown in this paper through a chronological compilation of 45 wells in 12 pads. Initially, CT milling job times were defined based on the minimum and maximum speeds while running in and pulling out of the hole, circulation fluid parameters to ensure turbulent flow and parameters for gel sweeps and wiper trips. Subsequently, a series of reviews of the data collected from operations was implemented, and the focus was shifted to operating times at the different job stages. This was followed by stream mapping the personnel and equipment assigned to each specific activity.

Additionally, Key Performance Indicators (KPIs) were defined, such as CT speed between the surface and the kick-off point, average speed between plugs, plug milling time, and time to return to surface while pulling out of the hole.

This journey to efficiency has been achieved by systematically introducing continuous improvements into our operations, utilizing on-site field personnel as the main driver and the engineering team as support, monitoring the execution, and taking action when needed.

After servicing 45 wells across 12 locations over two years, an 11% reduction of the total time in the well during frac plug mill out has been achieved. Considering that the lateral length of the wells and the number of stages has increased by 52% and 41%, respectively, this has enabled significant cost savings in a safe and effective way.

Operational efficiency has to be aligned with contemporary advances in the industry. As completion strategies evolve, so must our intervention methods. This paper documents how the completion life cycle of wells in a challenging, unconventional environment has been reduced through customized well interventions with CT.