bluuebunny/crossref_metadata_2025_split huggingface dataset:
Key Takeaways from Mobile, Self-Contained Multiphase Pumping Package Designed for Efficient Unloading and Production Boosting of High Gas Volume Fraction and Heavy Liquid Wells
Authors: Yudin K. , Kurimov D. , Benther A. , Putra E. , Nurmukhanbetov A. , Bekishev A. , Shugayev N. , Valdivia P. , Ivkin A. , Maximov P. , Hajjoubi H. 
Published: November 2023

Abstract
Tengiz Field has been in production for over 30 years period and as a result, some wells are not capable of producing fluids to the current system pressure. Several wells were shut in because of insufficient wellhead pressure, changes in well flow regimes, and in reservoir conditions leading to unexpected well loading and unplanned shutdowns. Tengizchevroil (TCO) has historically unloaded wells primarily by depressurizing the production line connected to the loaded well, lowering the wellhead pressure, and enabling the well to start up by itself without the need for further assistance. To kick off the well when flowline depressurization is insufficient, a fullbore nitrogen bullhead is injected through the kill line. This makes the hydrostatic column lighter and enables the reservoir to push it more easily. Both methods are costly and pose HSE risks associated with equipment movement, production line depressurization, pressure management, Joule-Thomson effect, brittle fracture risks, H2S gas leak risks, and CO2 and methane emissions due to fuel gas flaring. The Multiphase Pumping Package (MPP) project was initiated to develop a new solution to unload wells that stopped producing. The project required an agile solution with a high level of mobility, ensuring safe and faster deployment between metering stations reducing idle time, and minimizing the loss of production.
This paper shares lessons learned from using a Multiphase Pump (MPP) for unloading and boosting wells with heavy liquid at the bottom and gas at the top. It covers the MPP's fit-for-purpose design for mobile and self-contained applications, as well as its ability to operate under extreme conditions like high GVF (up to 98%) and heavy liquids. The paper will cover the following aspects of MPP applications:
The design aspects and criteria for MPP, including business requirements and limitations. MPP's surface tie-in locations and its mobility between different sites Operational challenges during well startups and unloading, as well as practical methods developed, and lessons learned.
Open Hole Packer Movement – The Last Piece of the Puzzle, Tubular Design
Authors: Kuswiranto A. , Cooke D. 
Published: November 2023

Abstract
Open hole packers for multi-stage fracturing completions have long been deployed with open hole anchors with a philosophy that these anchors will enable achievement for a successful well stimulation. The general perception in the industry is that the open hole completion in the well should be anchored to avoid open hole packer movement during a fracturing job. However, some questions are still unanswered such as: Are the open hole packers moving during the fracturing job? When are the open hole packers likely to move? This paper takes looks at several open hole packer movement analyses during stimulation.
To analyze the objective of this study, the focus was kept on the analytical open hole packer force and the movement tendency during a stimulation job. To answer the questions above, it is essential to evaluate analytically the effect of these induced axial loads during fracturing with open hole packers, which have been set with and without use of open hole anchors, in the completion string. Hence, this paper discusses the study and influence of; 1) high pressure and cooling effect during stimulation, 2) friction force associated with open hole packers, and 3) maximum force required for open hole packer movement, and 4) packer movement lab test data.
The results from open hole packer movement analysis performed for several cases has successfully estimated the maximum force needed for packer movement. The study addressed the un-answered questions and showed the requirement for either complete anchoring of all open hole packers or total elimination of open hole packer anchors during hydraulic fracturing.
Uncertainty of potential tubular failure, due to misinterpretation of open hole packer movement, can be determined earlier during the concept design stage, to avoid well integrity issues during the stimulation operation.
Pore-Scale Study on the Flow Dynamics of Coupled Low Salinity and Nanofluid Flooding in Carbonate Formations
Authors: Khalilinezhad Seyed Shahram , Duan Xili , Singh Kuldeep 
Published: November 2023

Abstract
A significant volume of annual world oil production comes from carbonate reservoirs like the giant Middle East and Caspian Sea reservoirs. However, the production enhancement is complicated by geological heterogeneities of carbonate formations, such as a complicated network of natural fractures leading to highly permeable paths or shale streaks leading to discontinuous flow barriers. The primary objective of this paper is a feasibility study of coupled low salinity and nanofluid flooding for oil recovery enhancement from carbonate reservoirs. Accordingly, diluted seawater and two different types of nanoparticles (NPs) were exploited to prepare low-salinity nanosuspensions to understand the synergistic effects of low-salinity nanofluid (LSN) injection on oil droplet remobilization. As the multiphase flow experiments were performed using glass micromodels, surface wettability analysis was also conducted on flat glass plates to clarify the role of NPs at the interfaces. The fluid flow around shale barriers and fracture/matrix interactions were qualitatively scrutinized at the pore scale using multiphase flow tests on the oil-wet microfluidic chips inspired by the pore structures of rock samples of carbonate reservoirs. The results of contact angle experiments showed that the inclusion of NPs into low-salinity water can ameliorate the ability of the aqueous solution to reverse the surface wettability of the oil-wet samples to a more water-wet state due to the improved adsorption isotherm of NPs into the glass surface. Microscopic and macroscopic observations of the porous media flow tests also disclosed that the LSN injection could significantly improve breakthrough time as well as microscopic and macroscopic sweep efficiencies. In other words, a slight viscosity improvement of injected water due to the presence of NPs could relatively diminish the extension of fingering patterns in porous media and create a better displacement front, resulting in a higher breakthrough time of displacing fluid. Furthermore, due to surface wettability reversal, LSN injection reduced the amount of untouched oil behind the shale streaks and showed better intrusion into the matrix and a higher fluid exchange rate between the matrix and fractures. This study proves the effectiveness of LSN injection in improving the efficiency of enhanced oil recovery from carbonate formations. Besides, we highlighted the flow characteristics of LSN around the shale streaks and high permeable fractures.
Application of Drag Reducing Agent DRA in Tengiz Field Gathering System to Reduce Frictional Pressure Drop in the Pipelines and Increase Production: Best Practices and Challenges
Authors: Nadirov Maruan , Moldabekov Bayan , Benther Arnoldo , Kurimov Dauren , Subramanian Sivakumar , Zhumagulov Kanat , Aitkazin Mirkhat , Nemanic Mike , Suleimenov Olzhas , Gubashov Rustem , Shorabek Zharas , Bekov Samat , Kuatov Asan , Orazov Baurzhan , Beisebayeva Ainur , Bopiyev Chingiz , Yeschanov Ilyas , Tauyekelov Medet , Kaiyrgaliyeva Zaira , Dyussenova Madina 
Published: November 2023

Abstract
Drag reducing agents (DRA) have been used in the oil and gas industry for decades to increase flow capacity of pipelines transporting petroleum products or crude oil over long distances. Injection of DRA reduces the flow turbulence, thereby reducing the frictional pressure drop in the pipelines and increasing pipeline throughput. Most of the time DRA is used in single phase flows, but application in multiphase flow conditions is growing. The surface gathering system of Tengiz oil field is complex and consists of more than 300 km of gathering lines and trunklines, some of which are bottlenecked due to their smaller diameter or high flowrates from the wells. TCO decided to implement continuous injection of DRA in parts of the production system to lower the frictional pressure drop in the bottlenecked pipelines and increase production from the wells.
The selection of DRA chemical was based on laboratory testing of the additive's compatibility with other liquids (such as caustic solution, produced water, corrosion and hydrate inhibitors) used in the field and plant processes, and on field trials. The obtained field test data was used to calibrate the network model in IPM GAP to simulate the reduction in pipeline friction losses due to DRA injection, and this approach helped to find future locations for continuous injection of the additive. As a result, continuous DRA injection was implemented at four injection points, which increased the total oil production from the field by 3%.
The purpose of this article is to share TCO's experience with the application of DRA injection in a multiphase flow system and describe all stages from selection of DRA and laboratory testing to modelling and actual execution of DRA injection in the pipelines of the Tengiz oil field. The paper discusses an overview of the current status of the DRA project, results obtained, best practices and lessons learned from field applications.
Feasibility of Foam-Enhanced Water-Gas Flooding for a Low-Permeability High-Fractured Carbonate Reservoir. Screening of Foaming Agent and Flooding Simulation
Authors: Derevyanko V. K. , Bolotov A. V. , Minkhanov I. F. , Varfolomeev M. A. , Usmanov S. A. , Saifullin E. R. , Egorov A. N. , Sudakov V. A. , Zhanbossynova S , Sagirov R. N. 
Published: November 2023

Abstract
The carbonate reservoirs of the Alekseevskoye field (Russia, Republic of Tatarstan) are complicated by high heterogeneity and the presence of fractures, which make development difficult due to early water or gas breakthrough depending on the injected agent, as well as low of the productive horizon. To increase sweep efficiency and introduce fractured reservoirs into development, it is necessary to use gas enhanced oil recovery (EOR) technologies. To find the optimal technology in terms of technological complexity and efficiency, three technologies were compared: Water Injection (WI), Water-Alternating Gas (WAG), and Foam Assisted Water-Alternating Gas (FAWAG). Series of core-flooding tests were implemented under reservoir conditions on carbonate cores, and cores with artificial fractures, saturated with original reservoir fluids. For FAWAG method compatible with high-mineralization water surfactant was chosen. Total recovery factor for each test was calculated. It was equal to 33%, 76% and 53% respectively for WI, WAG and SWAG, on the original core models. Therefore, WAG and SWAG were chosen as most effective techniques to improve oil recovery for in comparison with CWI. In artificially fractured cores, the WAG method recovery rate was 40%; subsequent injection of a foaming active substance mixed with FAWAG formation water proved effective, increasing the oil recovery rate to 47% due to partial blockage of the fracture.
Non-Matrix Uncertainty Management Through the Integration of Drilling, Production, and Seismic Data in the Supergiant Kashagan Field
Authors: Gabdullin A. M. 
Published: November 2023

Abstract
The Kashagan supergiant oil field is a naturally fractured and karstified carbonate reservoir located in the Precaspian basin of Kazakhstan. Karst manifests itself in multiple forms within the reservoir, but the most important forms are geobodies, which are presumed to represent paleocaves (Figure 1). The distribution and properties of the reservoir geobodies are highly uncertain since they can only be ascertained through the use of 3D seismic and well penetrations. The current wells show a high degree of variability in production performance (e.g. PI, rates) despite the relative proximity of the wells. This variability is assumed to be influenced primarily by the proximity to geobodies and associated non-matrix permeability. Therefore, a more robust validation of geobodies calibrated with production data will support updates to reservoir architecture in geological models and enable optimization of future well placement.
Hydraulic Fracture Propagation with Complex Natural Fracture Network in Lacustrine Shale Oil Reservoirs
Authors: Li Jie , Li Jian , Ma Fujian , Guo Zixin , Luo Yin , Liu Changchun , Niu Li , Chang Rui , Huang Zheyuan , Lei Qihong , Bukovac Tomislav 
Published: November 2023

Abstract
The challenges of lacustrine shale oil reservoirs include not only heterogeneity of reservoir quality, but also the effect of natural fractures on propagation of hydraulic fractures and associated fracture hits. The intercalated sandstone and shale in a gravity deposit setting result in significant variation of the reservoir quality both vertically and horizontally. The subsurface conditions become even more complicated when the reservoirs are naturally fractured. This study aims to characterize the natural fractures with seismic data and diagnose hydraulic fractures with microseismic data, fracturing data, and simulation data.
An ant-tracking algorithm was used with variance of the seismic data as the input to delineate natural fractures and to build the natural fracture model. A geological model and a geomechanical model were built integrating all available data, including logs, core data, and seismic data. The quality check was performed by analyzing various data and comparing these data with the three geoscience models. The data included drilling data, such as the mud loss; microseismic data and fracturing data, such as the observed neighboring wellhead pressure and pressure decline G function analysis; and, eventually, production data. A distributed fracture network (DFN) model was built with the ant-tracking results. Fracture stability analysis was performed based on the natural fracture model and geomechanical model.
The fracturing design was customized and optimized with the models mentioned above and understanding obtained from the analyses. High fracturing efficiency and positive production performance impact are benefits of the workflow.
The hydraulic fracture propagation is diagnosed mainly by microseismic data and fracturing data. Additionally, interaction between nature fractures and hydraulic fractures can be identified by fracturing simulations using an unconventional fracture model simulator for a complex fracture network with the inputs of the DFN and the geomechanical model derived from the 3D geological models.
Development of a Hydrate-Free Operating Mode Model for Gas Lift Wells
Authors: Andrianova A. , Yudin E. , Shestakov A. , Mosyagin G. , Polinov M. , Gudilov M. , Kobzar O. , Isaev D. , Ganeev T. 
Published: November 2023

Abstract
The purpose of this work is to create a model to ensure hydrate-free operation of gas lift wells based on data on pressure and temperature at well sites most prone to hydrate formation, inhibitor concentration, as well as historical information about previous hydrate formation at the site.
To achieve the objectives, first of all, statistical methods of high-frequency data analysis were used in order to automatically identify hydrate formation intervals at an early stage. Information about temperature and pressure at the time of the intervals identified algorithmically and confirmed in the field, was used as points of adaptation of the hydrate formation curve. Information on inhibitor concentration was also taken into account when constructing the curve. The resulting curve allows calculating the risk of hydrate formation at a particular node and recommending the optimal inhibitor concentration to ensure a hydrate-free regime. All results of the algorithm are displayed in the user interface in tabular and graphical form and are supplemented with information about the well and relevant nodes of the inhibitor pipeline system.
The result of this work is an implemented system for determining the risk of hydrate formation and making recommendations for the concentration of injected hydrate inhibitor. The methodology based on the use of historical data on hydrate formation in the node as points of curve adaptation allows to take into account the inaccuracy of empirical correlations in view of the possible irrelevance of information about the component composition of the fluid or the presence of components, which are not a parameter of the correlation relationship. The model can be used as a tool for online monitoring of hydrate formation risk in the node, depending on the current values of telemetry, and as a recommendation tool for drawing up the technological mode of the well and the selection of optimal planned concentration of inhibitor, which provides hydrate-free mode for all the nodes of the well. Using this system simplifies technologists work and allows them to focus their attention only on wells that require recommendations to adjust inhibitor concentration or are at risk of hydrate formation.
The novelty of this work is to build a system for planning or ensuring hydrate-free operation using the methodology based on the method of adapting the hydrate formation curve on the historical data.
Seismic Facies Clustering via Spectral Decomposition using Machine Learning
Authors: Mammadov O. , Shafiyev A. , Malikov R. , Asgarov H. , Karimli J. , Shahsenov I. , Yeleskina T. , Karimli I. , Abdullayev N. 
Published: November 2023

Abstract
Analyzing seismic data, particularly when engaging in attribute analysis and spectral decomposition is time-consuming and requires human resources involvement. Usually, interpreters manually select and blend frequencies to identify geological patterns in seismic data. To do a proper analysis, hundreds of combinations should be generated, which introduces notable human bias.
The study objectifies the automation of spectral decomposition interpretation through the application of machine learning techniques aiming to identify and classify distinct seismic facies.
The proposed algorithm includes an integrated approach of Self-Organizing Maps (SOM) and K-Means. The input data is the frequency, spectrally decomposed from seismic data and projected on a target seismic horizon. To ensure geological relevance, a broad frequency range is considered, and steps are computed using the Structural Similarity Index Measurement algorithm. The normalized data goes through the SOM algorithm and clusters similar patterns along the frequency axis. To reduce the number of clusters, SOM nodes go through the K-means algorithm. The quality of clustering is evaluated by analyzing the unified distance matrix with weights colored by the relevant cluster.
The proposed algorithm generates a single horizon containing clustered seismic patterns. These patterns are then compared to the geologist's interpretation outcome, which was based on the "best matching" spectral decomposition RGB blending. The algorithm successfully identifies and clusters mud volcanoes along with their invasion zones and chimneys into separate clusters. It also clusters channelized facies into 2-3 distinct clusters, automatically separates floodplain areas, and identifies poor data areas.
Due to the input of a wide frequency range, the algorithm goes beyond expected geological features. It enhances channel continuity and automatically identifies thinner channelized features that were not depicted on manually created maps. The algorithm's capabilities provide valuable insights and improve the overall accuracy of seismic data interpretation.
This paper introduces a novel algorithmic approach for interpreting seismic data that goes beyond traditional methods, and offers a fresh perspective on seismic data interpretation, by enabling fully automated and quick seismic facies clustering, reducing human bias, and improving feature identification. It offers practical applications in reservoir characterization and hydrocarbon exploration, as well as valuable insights for industry professionals, researchers, and decision-makers involved in seismic data interpretation and exploration activities.
Digital Transformation of Well-Engineering: Deploying an Integrated Cloud-Based Solution for Enhanced Performance and Collaboration
Authors: Morrison A. , Rakhmetov Z. , Vij J. , Huang J. J. , Mulyukova Y. 
Published: November 2023

Abstract
In 2022, Tengizchevroil (TCO) adopted and transitioned to a cloud-based well-engineering solution (combination of multiple engineering engines), an adoption that was built upon the successful implementations and learnings from other asset locations. The primary objective is to achieve enhancements in performance, integration of data and applications, and improved collaboration targeted for factory or pad well planning. This paper outlines the deployment process, significant milestones, utilization of agile methodology, and the benefits derived from this digital transformation.
After an initial agile workflow mapping and optimization exercise, offset well survey and drilling data were centralized in an integrated database to enable automation. Digital well planning templates were established, an optimized subsurface data integration workflow was implemented, and one-click drilling program capabilities were deployed. Additionally, a well-structured and prioritized backlog was created to define the minimum viable product (MVP). Prior to the final deployment, a dedicated 3-week bubble support/hypercare phase was conducted to ensure a smooth transition to the new engineering solution.
Due to the well-coordinated efforts throughout the journey, TCO successfully trialed and launched the integrated cloud-based solution in September 2022. User feedback was captured throughout the integration process and adjustments implemented within the templates. Full implementation for future factory and pad drilling planning is planned based on the milestones and benefits that were noted during the trial phase.
From an optimization standpoint, the implementation of advanced tools such as "copy basis of design", stick chart analysis, and automated trajectory, hydraulics, torque & drag (T&D) and anti-collision, has significantly reduced well-planning times. Interaction with sub-surface teams, and with other applications, has been significantly improved. The inclusion of inbuilt quality checks and automated engineering validation engines has ensured consistent well planning. And the fully interconnected engineering system provides automated adaptation after any re-planning modifications. Each development requirement underwent a thorough review, following an agile methodology, to implement TCO's requirements. On a global scale it has also been recognized that the Software-as-a-Service (SaaS) model leads to reduced operational expenditures.