bluuebunny/crossref_metadata_2025_split huggingface dataset:
Evaluating Waterflood Efficiency with Multiwell Retrospective Pressure Analysis
Authors: Zholaman A. , Yergaliyev K. , Zharylgassov Y. , Krichevsky V. , Surmasheva L. , Farakhova R. 
Published: April 2024

Abstract
The efficiency of waterflood becomes crucially important when initial reservoir pressure is depleted and the aquifer is proven to be weak. In order to maintain pressure, one must carefully calculate injection / production wells rate, injection targets, define the optimal locations for new injection wells or justify switching producers to water injection. All of these tasks require the cross-well pressure impact data. Paper describes solution of these tasks on a field in Aktobe region, Kazakhstan.
Laboratory Synthesis and Evaluation of Phosphorous-Tagged Polymeric Scale Inhibitors
Authors: Chen Shaohua , Aljeaban Norah A. , Chen Tao , Huang Tianping 
Published: April 2024

Abstract
Polymeric scale inhibitors (SIs) possess excellent dispersive and scale inhibition properties. In this study, a series of phosphorous-tagged polymeric SIs (PPSIs) were synthesized to inhibit calcium scale formation in synthetic brines. The design of chemical structure followed previous evaluation results from commercial polymeric SIs to make the synthesized products maintain a high efficiency of scale inhibition. The phosphorus tag of PPSIs will facilitate the detection of SIs for operators to plan a reasonable squeeze treatment. Among three commercial SIs, AA/AMPS was the best one with a scale inhibitory efficiency of 100% at above 75 ppm. While HPMA exhibited little effects on inhibiting scale formation. Regarding the synthesis work, two polymer series including six specific PPSI samples were synthesized using 1 mol% of diethyl allylphosphonate and various AMPS or SSA and AA. 31P NMR spectra exhibited only one peak which corresponds to DEAP as the phosphorous tag. 1H NMR spectra indicated correct chemical structures of the PPSIs. The synthesized PPSI products showed good thermal stability, high efficiency in scale inhibition, and most importantly, the phosphorous detection by ICP. SEM images showed that the cubic and needle-like morphology of CaCO3 and CaSO4 scales were both significantly deformed upon addition of the PPSI to avoid the scale formation at a macroscopic level. After injection of one synthesized PPSI sample at a high concentration (10 wt%) followed by a shut-in period of 24 hours, permeability of the carbonate core plug was slightly changed, suggesting a low formation damage to the carbonate reservoir. After the post-flush of reservoir brine, the concentration of PPSI was still higher than the minimum inhibitor concentration (MIC), indicating an effective scale control during the squeeze lifetime.
A Novel Time Series Approach to ESP Gas Lock Predictive Classification Based on Dynamic Time Warping & K-Nearest Neighbor
Authors: Ghanduri Fatima 
Published: April 2024

Abstract
Electrical Submersible Pump (ESP) systems are a widely used Artificial lift method in the Oil and Gas industry- however, they do present failures with consistent use, as does any other tool. It is important to reliably predict the onset of damaging operating conditions and take proactive action to prevent early failure of ESPs.
Data processed from ESPs are considered time series due to their time-sensitive occurrences. Deep learning methodology needs to be adapted to the time series conditions of this data. Current deep learning methods deployed in the industry have demonstrated superior performance under the general requirement of the availability of a large set of training instances. However, many lack the efficient adaptability of the time component in the prediction of tool failure. Existing solutions do not further consider detecting signal similarity and reliable time alignment between pattern-matching measures. With this, we propose the use of K-Nearest Neighbor (KNN) with Dynamic Time Warping (DTW) as a distance-based classification method to classify the deficiency of a tool accurately and efficiently while considering pattern matching in specified time intervals.
The amalgamation of DTW and KNN is considered an effective method for time series classification of ESP gas lock prediction. Although the time complexity of this approach is considered as lower efficient than that of methods such as Time Series Forest Classifiers and Support Vector Machines, our approach optimises the search space and speeds up the execution at a more effective rate, thus providing a novel way for ESP predictive maintenance.
Improvement Strategy Heating and Drainage in Reservoir Complex Structure with High Faulted and Dipping in Area-9 D Field Heavy Oil Steamflood
Authors: _ Fatichin , Anggreini Selvyn , Pradana Candra Arya , Nugraha Baruna Satria 
Published: April 2024

Abstract
D field is the world's most significant operational steam flood that is currently produced from 13 existing areas. Area-9 is the most structurally complex in the D field. The existence of many faults and reservoir dipping is the primary issue that creates a complex compartmentation in the reservoir with faulting orientation mostly NE-SW and dipping to the East direction. The complexity of structure in Area-9 impacted the connectivity problem of producers’ and injectors’, caused reservoir heating and drainage not optimum, and impacted a low current recovery factor (RF) of ~45% compared to other mature areas with RF of 80%. The previous strategy to improve drainage and production in Area-9 by performing chemical jobs in many immature wells could not have improved heating, drainage, and production more effectively. A new strategy implemented to improve drainage, heating, and production in Area-9 established using the Area-9 conceptual model aims to get a deeper understanding of injection and production performance that links to faulted reservoir and compartmentalization. The improvement jobs that were applied for the Area-9 conceptual model are reactivating some of the idle steam injector wells in both surface and subsurface facilities to improve the heating of immature wells and patterns, performing some stimulation steam cyclic injection in surrounding producer wells located at the down dip of the pattern to connect steam between producer to an injector that can improve heating and drainage of the reservoir, perform some of the chemical stimulation jobs for mature well to improve well and pattern drainage. Ensure the reservoir temperature is already hot (mature) to ensure the chemical material works appropriately. By performing a new strategy, using Area-9 conceptual model successfully proved to improve heating, drainage, and production and unlock significant remaining oil opportunities. Some achievements of implementing the new strategy are improving heating by 30 – 60 deg F/job, increasing oil production by 7-15 bopd/job, and improving declining production performance in 2021-2022 (+2%) compared to 2020 (-7%). This effort has become a lean sigma project with a total Actual Financial Benefit (AFB) of ~ $2.5 MM. The next plan for applying a new strategy to improve heating and drainage in Area 9 is to consistently execute proactive thermal stimulation jobs and reactivate some of the injector wells. Future develops pattern alignment in Area-9 by adding more producer, injector, and observation wells to be aligned to the Area-9 conceptual model.
Integrating ASP Flooding into Mature Polymer Flooding in Marmul Field in Southern Oman
Authors: Mahruqi Dawood , Karpan Volodimir , Rawahi Hamza , Abri Mohammed , Aamri Nawal , Farsi Samya , Battashi Mundhir , Amri Sulaiman 
Published: April 2024

Abstract
The Marmul field is a medium-large mature oil field situated in the Southern part of Oman. Due to the relatively high viscosity of Marmul crude (~90 cP at reservoir conditions), polymer and ASP flooding were selected as the technology to improve the oil recovery beyond that of waterflooding. The commercial-scale polymer flooding in Marmul has been ongoing since 2010 and recently further expansions plans were announced. ASP flooding was extensively studies through the laboratory tests and field trials. Two field trials (Pilot and Phase-1A) with different ASP formulations and targeting different target reservoir intervals indicated a potential of 20-30% incremental oil recovery due to ASP injection after the water flooding. In the ongoing ASP field trial (Phase-1B project), the ASP solution is being injected in the quaternary mode to test the post-polymer performance of ASP flooding under field conditions. Post the technical success of the ASP Phase-1B project, the task was to identify the optimal concept for the ASP flooding in the Marmul field.
A hybrid approach based on numerical modeling and data-driven capacitance-resistance modeling was proposed to calculate the incremental oil recovery due to ASP flooding for the well patterns. Moreover, this publication presents the approach to integrating the ASP flooding into the mature polymer flooding in the Marmul oil covering both subsurface and surface aspects.
Marmul well patterns are both water and polymer flooded; hence an attempt was made to evaluate the efficiency of ASP flooding for both post-polymer and post-water injection conditions. Data from core flooding experiments and field trials were used to forecast the efficiency of ASP flooding post-water and post-polymer flooding. Moreover, to take into account the properties variation across the field a set of field parameters such as reservoir heterogeneity and mineralogy, remaining oil saturation and its distribution, well performance, etc., was used to forecast the performance of ASP flooding in different well patterns. Resulting pattern-specific oil recovery was used in an economic evaluation to select the optimal concept for the commercial-scale ASP flooding project in Marmul.
An Integrated Governance Technology Based on Magnetic Steering System for Cementing Plug in Open-Hole Section of Underground Gas Storage: Theoretical Analysis and Field Test
Authors: Che Yang , Yuan Guang Jie , He Ai Guo , Qiao Lei , Liu Tian En , Fang Ming Xing 
Published: April 2024

Abstract
The paper describes a comprehensive control technology based on a magnetic steering system for plugging the cementing plug in open holes without clear beacons in underground gas storage (UGS).
Utilizing depleted oil and gas reservoirs for natural gas storage is an important approach towards achieving carbon neutrality. Plugging old wellbores that affect sealing performance is prioritized according to relevant standards.
The challenge with open holes with cement plugs is that there are no clear beacons in the wellbore, and the extent of compaction is unknown. Accurate positioning of the cement plug is crucial and the current technical methods, such as electromagnetic and acoustic waves, have limitations. Magnetic steering technology, which is mature and widely used in drilling complex structure wells, requires beacons like pipes and metal pipe strings. On the other hand, acoustic positioning technology is still experimental and suffers from large distance and azimuth errors due to the attenuation characteristics of acoustic waves in heterogeneous formations. These existing technologies are unable to directly position open holes with cement plugs.
The paper proposes a comprehensive control technology based on the magnetic steering system. It starts by measuring the positional relationship between the drilling wellbore and a magnetic reference wellbore using the magnetic steering system. The skew data is then used with the ISCWSA model to determine the location of the plugged wellbore and the magnetic reference wellbore. By calculating the relative positional relationship between the drilling wellbore and the plugged wellbore, the cement plug reentry can be achieved within the error ellipse range below the sidetracking point. After reentry, specific work such as crushing, element logging, caliper logging, and full hydrocarbon gas detection is performed to verify if the wellbore is still in the original position and if the caprock is properly squeezed and plugged.
The comprehensive treatment technology plan was tested on five wells in the Bohai Bay, successfully addressing the problem of positioning open holes with cementing plugs. The process system expands the field of magnetic guidance technology and demonstrates significant industrial application value. It provides a means of plugging complex old wells.
Incinerator Performance Improvement by Preheat Feed Streams Using its Produced Steam_ Reduce Operation Cost & CO2 Emission
Authors: Alzamzam W. S. 
Published: April 2024

Abstract
Sulfur Recovery unit is an essential part in Oil Refinery and gas treatment unit, it consist of MDEA enrichment unit, Claus Unit, Tail gas treatment unit and thermal incineration unit. Incineration process is used in order to make the process effluents releasable into the atmosphere. In which the hazardous and pollutant sulfur containing compounds are converted to sulfur dioxide. The case study of this work is about an existing thermal incinerator in Sulfur Recovery Unit, its streams are mainly consist of combustion air, MDEA waste gas, tail gas and fuel gas. Feed stream temperatures will be maximize more than current operating temperature in order to reduce fuel gas consumption and CO2 emission as well. The idea is utilized the produce high pressure steam from its Waste heat Boiler WHB to preheat feed stream including combustion air 40°C and tail gas 140°C and MDEA waste gas 40°C. in this study the target preheating temperature is 290°C for each stream. PROMAX Software is used as simulation tool, three scenarios have been chosen including maximize tail gas temperature, combustion air temperature and finally waste gas temperature. All input field date have been collected from operating system called distribution control system (DCS). Result show remarkable reduction of fuel gas consumption and CO2 emission for three scenarios (12.5%, 26 % and 36% respectively) comparing to existing situation for the case study. So installing high pressure steam pre-heaters on feed streams is strongly recommended for this case study in order to reduce operation cost and CO2 emission.
Optimizing Field Performance with Flow Control Technologies: A Case Study of Reducing Carbon Intensity in Oil Production in the Sultanate of Oman
Authors: Harthi M. , Moradi M. , Lawati A. , AlJumah A. 
Published: April 2024

Abstract
Reduction of carbon emissions has become a global objective driving both government and private sectors to develop and mature technologies that fit this purpose. This paper will evaluate how deploying rate-controlled production (RCP) Autonomous Inflow Control Devices (AICDs) in a field, with hundreds of wells completed with AICD completion, reduced carbon emissions during prolonged periods of production. The study introduces a workflow that uses a publicly available Greenhouse Gas (GHG) estimator for different field development plans.
The production data of 28 wells from a reservoir in the Sultanate of Oman were analyzed. The RCP AICD is a self-regulated based on the properties of the fluid passing through, which optimises oil production while reducing the production of unwanted fluids. To ensure an accurate comparison, the data underwent extensive pre-processing, and some modelling was conducted. The collected data, including fluid properties, formation characteristics, and operational processes were all used to feed the estimator, which then run for various scenarios with and without AICD cases to predict the energy consumption and greenhouse gas emissions associated with each operation and treatment involved in the field development.
By calculating these emissions, operators can identify the major sources of emissions and energy consumption and optimize their processes to reach net-zero. The results show that the use of AICDs completion in the wells has resulted in reduced capex and opex including drilling a reduced number of wells (both producers and injectors), less requirement of energy extensive production, surface processes and re-injection of unwanted fluids to achieve the target production rate for the field.
The study's findings revealed that AICDs have significant effects on improving oil production by 217% while reducing total water production by 52%, as well as on the environment. For instance, the use of AICD completions in the field was estimated to reduce carbon intensity, greenhouse gas emissions, and energy consumption by up to 51%, 47%, and 110%, respectively; compared to stand-alone screen (SAS) is installed in the other wells. Also, the finding shows that production operation was a major contributor to GHG emission and energy consumption for non AICD completion scenarios compared to any other operation or process involved in oil production.
This study provides a comprehensive workflow to quantify the impacts of the use of new technologies, especially flow control devices on the reduction of carbon emissions. It also illustrates the significant role of flow control technologies toward net zero targets by achieving less carbon intense oil production.
A Dynamic Reservoir Modelling of Carbon Dioxide Storage in Depleted Dry Gas Reservoir in Northern Oman: A Case Study
Authors: Al Ajmi A. , Ivanov D. , Kazemi A. , Al-Maamari R. , Bogachev K. 
Published: April 2024

Abstract
The objective of this study is to evaluate CO2 storage potential of a small gas field located in Northern Oman using advanced reservoir simulation techniques. The field is to be used for CO2 storage in the future when this reservoir is depleted. The study includes the estimation of structural, residual, solubility and mineral trapping mechanisms, as well as determination of safe operating pressure limits for CO2 injection.
The study utilizes various reservoir simulation methods to investigate each trapping mechanism, taking into account the hydrodynamic, physical, and chemical conditions within the reservoir. Specifically, solubility trapping is analyzed using Henry's law, while residual trapping is modeled using the critical gas saturation via Corey correlations. To analyze risks of faults reactivation and leakage into overlying formations, the geomechanical analysis was applied in the study. At the end of the study, a sensitivity analysis is performed to assess the influence of uncertain parameters for each technical approach.
The results of the case study provided both quantitative and qualitative evaluations of each trapping mechanism for the gas field. Potential deformation and fracturing of the caprock trap were predicted to ensure it remains intact to prevent CO2 leakage. Additionally, the study demonstrated the practical application of various reservoir simulation techniques for modelling CO2 storage, adding further value to the study. In spite of the fact, that the gas field has been well studied during exploration and production periods, including previous reservoir simulations, a sufficient level of uncertainty still exists in reservoir description, fluid and rock properties and even was increased with adding CO2 storage approaches. This study took into account these uncertain parameters, and probabilities were calculated for the estimations of trapping mechanisms.
This case study presents a complete modelling cycle for CO2 storage within a depleted gas reservoir, employing a range of diverse reservoir simulation techniques. It serves as a valuable guide for those interested in modelling CO2 storage through the application of various reservoir simulation methods.
Strengthening Well Abandonment Process Through Well Retirement AI Digital Advisor
Authors: Reddicharla N. , Alshehhi S. , Cristea Z. , Ali Sultan Ali M. , Gonczi D. , Toumi O. 
Published: April 2024

Abstract
The Operator manages a diversified and dynamic portfolio with thousands of wells. As the production methods evolve from naturally flowing to improved and enhanced oil recovery methods, artificial lift, unconventional and sour hydrocarbon reservoirs, the wells stock is continuously exposed to a changing spectrum of operational conditions that will eventually have an impact on the expected wells’ life span. The safe retirement of wells at the end of lifecycle through proper Plugging & Abandonment (P&A) operations, along with drilling and commissioning of replacement wells, has a significant cost impact in the long term. From this perspective, the Operator implemented its one-of-a-kind, innovative well retirement digital advisory solution to forecast candidate wells for P&A based on advanced data analytics and automation.
It is crucial to build a well-established workflow to simplify the well abandonment process to assure that no more value can be generated, or integrity cannot be restored. The well abandonment definition is related to remnant life, integrity, cost, and priority. The important components are reservoir health and well integrity. Digital advisor integrates reservoir simulation forecasts with the lifespan of wells based on production/injection, long-term profile and economic value. The system automates the ranking of well integrity candidates which are not fully in compliance with integrity management standards. Risk assessment is embedded in the advisor by defining the business impact of the wells. Data is automatically captured by predefined schedules from instrumentation and flat files, and operational data storage under relational database management systems.
This well retirement advisor provides a deterministic retirement candidates list, assuming each well's lifetime of 25 years from well spud date. It enables fast identification of P&A candidate wells based on reservoir health considerations. The time optimized list is updated with well integrity data statistics and forecasts. The approach has been tested in a mature oil field that has more than 800 wells and successfully identified the prioritized list of well retirement candidates. It provided a solid and consistent basis for the long-term projections of P&A candidate wells.
This advisory system helps to meet production targets through on-time replacement wells. This application has the potential to reduce OPEX cost through reduction of suspended well in the asset. It helps to proactively prepare for the well abandonment phase. Data availability and quality is critical for the successful implementation of applications such as the Well Retirement Advisor.
A Case-Study on Dynamic Quantum PLT Method Applied for Separate Accounting of Produced Fluids in Case of Commingled Production
Authors: Titovsky Nikita , Vasechkin Dmitry , Saprykina Kseniya , Upadhye Vishwajit 
Published: April 2024

Summary
An oilfield operator has a requirement and therefore faces a challenge of separate production monitoring and accounting of production fluids for each reservoir, in the field case of dual completion and commingled production from different reservoirs. The existing assessment and tool-assisted methods offer only a partial solution to this problem. This article discusses the use of quantum PLT technology in directional wells by installing downhole a bottom-hole dual completion assembly equipped with quantum marker inserts for separate monitoring of production from different reservoirs.
To enable separate production accounting with the use of the dynamic quantum PLT method, a straddle packer system with quantum marker inserts carrying unique inflow indicators for each production interval is installed in the cased wellbore. When contacting hydrocarbons and water, markers are released from the composite material into the fluid. In the course of the steady-state well production, wellhead fluid samples are taken sequentially. The completion assembly provides for separate accounting for each production formation without the need for well shutdown and withdrawal of pumping equipment. The samples are analysed in the laboratory using the flow cytometry method to quantify the production distribution across the well zones.