bluuebunny/crossref_metadata_2025_split huggingface dataset:
Successful Leak Repair and Restoration of Oil Production a West Kuwait Case Study
Authors: Elias M. , Tagarieva L. , Abu-Eida A. , Al-Azmi N. , Patra M. , Al-Sabea S. 
Published: October 2023

Abstract
Two West Kuwait oil wells were completed with initial flowrates of 3,000 and 5,000 stb/d with zero and 25% water cut, respectively. However, water cut increased quickly to 100% for both wells. Therefore, a production logging program was developed to find the source of water flow. Once the source was found a well workover plan was developed. Well intervention was done along with Production Logging to detect the water source and to verify well integrity.
Due to the change in well production from oil to water, the operator requested aid in identifying the cause of the production change. The first step in the process was a production logging run, both flowing and shut-in to prove well flow parameters and to identify the source of the water. This involved logging both the completion of interest, with the ability to log other sections of the upper completion if the water source was not initially found. Once the water sources were located a well remediation plan was developed to re-establish both wells production baseline.
This paper presents the results from two wells, which initially had the same issue: water production from the upper completion. However, the actual results highlight the capability of production logging to identify the root causes of production drop-off. In the first well, the PLT run discovered no water production from the lower zone, but dump flooding from an upper zone that shut off oil production. The upper zone water production was from a corroded completion, repaired with a perf and squeeze shutting off the water flow. The second well could only be logged during shut-in, where the sensor responses were consistent with water ingress, however, the flowing pass had no sensor responses. This was caused by the jetting of the water inflow from casing damage in the formation above the production zone, making sensors' responses invalid. The shut-in pass clearly showed the location of water ingress, from a casing failure in the completion above the production zone resulting in dump flooding and shutting off oil production. The remediation in this instance was a mechanical repair followed by a cement squeeze to isolate the water zone. Production testing and follow-up PLT runs confirmed the elimination of water production and 100% oil production.
This case study shows the power of PLT programs to find water ingress points, even when the inflow is not in the completion zone of interest. This allows the operator to plan remediation programs that results in a return to normal or near normal production levels.
Multilateral Completion Technology to Improve Reservoir Management
Authors: Ameen Yousef , Almasri Abdulrakeeb , Saleh Abdullah , Alkadem Mortada 
Published: October 2023

Abstract
Effective well completion design is crucial to optimize well and field performance, with many operators utilizing different techniques to achieve this important objective. However, the conventional means of designating wells for reservoir monitoring and standalone wells for production presents challenges to cost-effective reservoir management.
Vertical observation wells are usually drilled in different locations to monitor the reservoir and assist with planning and intervention decisions by running periodic logs to obtain subsurface information. However, these wells can be costly and occupy valuable space that could be utilized for production. An alternate technique is to drill a pilot hole, perform all the necessary logging, and obtain the required reservoir information. The pilot hole is then plugged and sidetracked to a producer well. Nevertheless, the collected data only remains valid for a limited period due to potential changes to the reservoir.
The demand for cost-effective, optimized drilling of production and observation wells has led to a paradigm shift in multilateral well technology that achieves both production and monitoring objectives for both laterals at the same time. Using this enhanced technology, wells can be completed with a pilot hole (vertical) drilled for reservoir evaluation throughout the life of the well, with permanent downhole gauges (PDHGs) installed for pressure and temperature monitoring, while the horizontal lateral functions as an oil and gas producer. Combining the observation and producer wells into one well results in cost savings and enhanced reservoir production and surveillance programs. In addition, the capability to access the lateral allows for intervention in both the motherbore and lateral at any time.
Well intervention operations for a well completed with this multilateral technology involve slickline runs to gain access to the horizontal lateral, retrieve an isolation sleeve, and install a tubing exit whipstock (TEW) for lateral re-entry. Later, coiled tubing (CT) or wireline tractor can be run through the window into the lateral to perform the logging and intervention necessary. Upon completion, the TEW is retrieved from the window, the isolation sleeve is reinstalled, and the well is returned to production. Well intervention through such multilateral completion demonstrates the ease and efficiency of accessing both the vertical and horizontal lateral, without requiring a rig or completion retrieval.
This paper will highlight the multilateral completion technology for accessing both laterals, which includes real-time monitoring capabilities that provide more reliable data for optimum well and field performance.
Case Study: An Effective Solution to Operate ESPs in the Severe Erosive Environments of Unconventional Wells in the Permian Basin
Authors: Villarreal Paola Elizabeth Martinez , Morales Diego Armando Marquez , Briceno Argenis Alberto Garces 
Published: October 2023

Abstract
This case study presents the results of implementing nickel coating on the stages of electrical submersible pumps (ESPs) to extend their run lives in unconventional high-flow-rate wells in the Permian Basin.
The ESPs analyzed in this study previously had short run lives of less than 140 days; the failure reason was severe wear in the pump stages and severe erosion of the housings that led to the detachment of part of the string in the hole in some of the cases. The solution implemented involved the research, analysis, testing, and improvement of manufacturing processes of the proper coating and its application on the pump and gas-handling stages to increase their durability and resistance to abrasion and erosion.
This solution was tested and successfully implemented in four unconventional wells producing from the Cline Shale, which is in the eastern part of the Permian Basin. The following are the well conditions: flow rate of 4,000 B/D, pump setting depth of 6,000 ft, 160°F bottomhole temperature, and perforation depths of 7,000 ft. The implementation and results demonstrated the feasibility of the solution that can be potentially implemented in other oil-producing wells in the Permian Basin.
Drawing on real-world experiences and considering various factors, this case study provides valuable insights and recommendations for operators and engineers working with ESPs in challenging erosive environments. It serves as a valuable resource for improving the reliability and lifespan of ESP systems, ultimately contributing to enhancing operational efficiency and reducing downtime due to frequent workover operations because of failures related to the presence of sand.
The Multiple Bedding Planes (BPs) Effect on Fracture Height Propagation: Experimental Study and Field Data Analysis
Authors: Shuai Li , Bo Cai , Dingwei Weng , Chunming He , Xinbin Yi , Haifeng Fu 
Published: October 2023

Abstract
Geological structures such as pre-existence of multiple bedding planes (BPs) significantly influence the hydraulic fracture height propagation in shale gas and shale oil reservoirs. Field engineers have also proved that fracture height is much lower than designed via monitoring such as microseismic and DTS/DAS test.
In this paper, hydraulic fracturing simulation is studied by injecting fluids into a 1m×1m×1m rock-block sample with multiple thin BPs developed at the in-situ stress condition, and during the operation process, acoustic emission (AE) monitoring is used to obtain the fracture propagation events. After the fracturing physical simulation, we cut the rock sample from three different perspectives and take visual observation of the fracture geometry via fluorescence irradiate. Secondly, we carried out series field data analysis such as fracturing curve history matching, flow-back data analysis and production data analysis, aiming to find the correlation between fluids leak-off rate, flow-back salt concentration, fracture height, fracture complexity and the number of BPs.
Results showed that fracture propagation is a competition controlled by stresses and rock BPs. Fracture propagation is generally perpendicular to minimum principal stress while is locally controlled by the rock BPs. It always initial to be vertical fractures near the wellbore area, while as the vertical fracture penetrates the BPs, fracturing fluids would leak into the BPs and form horizontal fractures, lead to slow propagation in height direction and change the final fracture geometry. Fluorescence irradiate also showed fracture propagation can be divided into three modes, directly penetrate the BPs, arrested by the BPs or bifurcate into BPs, and these are mainly depending on the high-angle natural fractures. The results of this study suggest that a significant portion of fracturing fluids could be retained in BPs, which in turn is the reason of fracture height propagation obstruction. In field data analysis, we find that fluids leak-off rate has positive correlations with BPs number, fracture complexity and hydrocarbon production. Flow-back salt concentration (salinity) also has positive correlation with BPs number while has negative correlation with fracture height. Ratio of fluids leak-off and fracture height (Vleak/Hf) or ratio of flow-back salt concentration and fracture height (Cf/Hf) can be used as evaluating indicators for the number of BPs that fracture penetrates through.
Experimental study and field analysis of the BPs effect on fracture height propagation can provide constructive guide for the hydraulic fracturing of BPs developed reservoirs.
Modelling of Partially Miscible, Multiphase Hydrocarbon Mixtures Using a Fugacity-Based Lattice Boltzmann Method
Authors: Soomro Muzammil , Ayala Luis F. 
Published: October 2023

Summary
A thermodynamically consistent, fugacity-based lattice Boltzmann method (LBM) is used to carry out simulations of multicomponent, multiphase hydrocarbon mixtures. The mixtures are simulated as partially miscible and a multicomponent equation of state (EOS) is incorporated into LBM through the fugacity. Vapor Liquid Equilibrium (VLE) cases and dynamic cases are presented for different hydrocarbon mixtures. The free energy LBM model, applicable to multiphase systems, makes use of a functional of the (Helmholtz) free energy. Traditionally, this free energy has been limited to empirical "double-well" models and very limited use of EOSs. A new approach utilizing component fugacity bypasses the need for a free energy functional. The fugacity provides a link to incorporate multicomponent EOSs into LBM, resulting in an accurate modelling of hydrocarbon mixtures. We use this fugacity-based LBM to carry out VLE simulations for a binary hydrocarbon mixture to generate pressure-composition and temperature-composition plots. Next, we extend VLE simulations to cases of ternary hydrocarbon mixtures. In all cases of VLE, results from LBM are compared with the results obtained from a flash calculation and are shown to be in excellent agreement. This is significant as the LBM has a legacy of thermodynamic inconsistency due to which such agreement is hard to achieve. Next, we simulate far from equilibrium systems by considering the case of spinodal decomposition for a binary mixture. A homogeneous system is observed to decompose into separate phases, consistent with thermodynamic principles, when initialized in the unstable region of the phase envelope. Our results show the fugacity-based LBM to be a highly accurate model for hydrocarbon mixtures when it comes to capturing thermodynamic equilibrium and fluid dynamics. This study presents a comprehensive analysis of multiphase, partially miscible hydrocarbon mixtures using a lattice Boltzmann model which is consistent with thermodynamics and offers predictions in line with accurate equations of state. This opens the door for realistic pore-scale simulations of hydrocarbons which can be upscaled to develop better reservoir simulators.
Embedding Existing Pipelines in Design of CO2 Transportation Networks for Optimal Sequestration Economics
Authors: Nnamdi D. , Moghanloo R. G. 
Published: October 2023

Abstract
This paper presents a method for incorporating existing pipelines into the design of optimal CO2 transportation networks for carbon sequestration projects. The selection of the optimal pipeline transportation network is a crucial aspect of large-scale carbon sequestration projects as it greatly affects the project's economics. The method proposed in this paper aims to address the limitation of existing open-source tools such as SimCCS2.0which are unable to accommodate existing pipelines in techno-economic optimization. With the recent amendment to the 45Q laws, which now offers 70% more tax credits for carbon sequestration than in 2018, energy companies are exploring the possibility of repurposing gas and liquid transportation lines for CO2 transportation to abandoned oil and gas wells for carbon sequestration. This has further reinforced the need for a method that accounts for existing pipelines in sequestration economics.
The proposed method achieves this by representing the pipeline paths on the construction cost graph as zero-cost paths. Additionally, pipeline tie-in locations are fixed by creating exclusion zones that limit inflow edges around the pipeline path. The solution is then obtained by solving for candidate transportation network routes using graph shortest path algorithms. This reformulation of the CO2 source-sink connection flow problem with limiting constraints on existing pipeline flow direction and capacity makes it possible to assess cost reduction associated with different CO2 sources tie-in locations along existing transport pipelines.
The solution was developed using the Python programming language, and small-scale demo test cases have been used to illustrate its effectiveness in four tie-in cases with single pipeline and multiple pipelines that cut across several CO2 source and sink locations. The method has also been applied to the evaluation of a proposed CarbonSAFEII project and the results used to assess optimal pipeline tie-in points for expanded sequestration capacity.
The developed python package is publicly available on GitHub for researchers and economic analysts to use for evaluating large-scale carbon capture, utilization, and storage (CCUS) projects, with the aim of encouraging further development and collaboration.
Advanced Characterization of the Jansz-Io Field Using AI-Assisted NMR Workflows
Authors: Waugh Matthew , Qleibo Meretta , Xingwang Yang , Jain Vikas , Cheong Boon Cheng , Daud Saiful Hakimi 
Published: October 2023

Abstract
The Jansz-Io field is part of the ‘Greater Gorgon’ project, situated approximately 120km offshore the northwest coast in the Northern Carnarvon Basin offshore Western Australia. This study presents a two-part workflow for determining petrophysical and grain-size related properties of the late Jurassic Jansz Sandstone in the Jansz-Io Field. This field contains highly variable clays and cements distributed both vertically and spatially due to bioturbation and diagenetic processes. The relationship between saturation and pore structure, important for reservoir evaluation and modeling, is not well understood. The objective of the study is to use class-based machine learning (CbML) and nuclear magnetic resonance (NMR) pore-to-production workflows to improve the understanding of the reservoir properties. This will also reduce uncertainty in gas initially in place (GIIP) and estimated ultimate recovery (EUR) during static and dynamic modeling workflows.
The first part of the workflow involves applying CbML to determine petrophysical properties. CbML was used to classify well logs into facies based on rock types. The resulting classification was used to determine core-calibrated continuous petrophysical properties in all wells. In the second part, novel NMR pore-to-production workflows were used to determine grainsize related properties. NMR data from 19 wells were normalized against different acquisition technologies, vendors, and conveyances using factor analysis and fluid substitution methods, to determine textural facies, effective porosity/water saturation, and grain-size distribution across the field.
The workflow comprising CbML and NMR pore-to-production methodologies shows how AI/ML can assist alongside conventional workflows to maximize the return on investment of measurement acquisition. The results show that the fluidsubstituted NMR distribution and grain-size distribution by textural facies is integral to understanding the relationship between permeability, porosity, water saturation, and grain size. Insights from this study are being used to update the geological deposition model to reduce uncertainty in GIIP and EUR during static and dynamic modeling workflows.
The integrated workflow enables the determination of continuous core-calibrated properties required for not only petrophysical evaluation but also for geological and reservoir modeling to optimize completions and production. The significance of the study lies in its ability to improve the understanding of reservoir properties and reduce uncertainty in GIIP and EUR, leading to more accurate reservoir modeling and optimized production. The novelty of the study lies in the combination of CbML and NMR pore-to-production methodologies to determine petrophysical and grain-size related properties of the Jansz-Io Field.
Expanding Sweep Volume Effect and Mechanism of Pulse Injection Improving Viscous Fingering
Authors: Chen Xin , Li Yiqiang , Liu Zheyu , Liu Shun, , Trivedi Japan , Liao Haiying 
Published: October 2023

Summary
Viscous fingering of the injected fluid will significantly reduce the swept volume. Increasing the injected fluid viscosity can impress viscous fingering, but the reservoir and economy limit its application. Exploring a simple, effective, and universal viscous fingering impression method can effectively improve secondary oil recovery efficiency. This paper focuses on the effect and mechanism of pulse injection to expand the swept volume and provides experimental guidance for related pilot applications. Microfluidic and core fluidity experiments were conducted using large-scale glass chip and artificial cores, respectively. Including four constant-velocity and nine pulse microfluidic experiments under four injection rates (40, 1000, 300, and 5000 nL/min), three pulse frequencies (0.1, 1, and 10 Hz), and three pulse amplitudes (0.25, 0.5, and 0.75). Image recognition can quantitatively characterize the expanding swept volume efficiency of pulse injection. The macroscopic effect of pulse injection was verified by core fluidity experiments, and the mechanism of pulse injection expanding the swept volume was given from two aspects of force analysis and invasion front backflow. The results of constant injection experiments show that increasing the injection rate will cause the invasion front to transition from capillary fingering to viscous fingering, but the final swept volume first increases and then decreases. Pulse injection can transform the invasion front morphology from a multi-branched structure to a thicker one- or two-channel structure. Moderate pulse frequency and high pulse amplitude are beneficial to pulse injection to expand the swept volume. When the frequency is 1 Hz (amplitude is 0.5), and the amplitude is 0.75 (frequency is 1Hz), the swept volume can be expanded by 9.38% and 12.51%, respectively. The results of core flooding experiments show that pulse injection can increase water permeability. Pulse injection can generate fluctuation of injection pressure by the periodic change of injection rate, equivalent to inputting additional energy into the injection system. The additional pressure gradient is the fundamental reason for promoting the expanding throat flow and swept volume. Besides, the pulse injection leads to the inhomogeneous backflow of the invasion front, shortening the distance of multiple flow channels and delaying the formation of dominant channels. This work innovatively use low-frequency pulse injection as a universal method to improve viscous fingering and propose the mechanisms of pulse injection improving pore throat flow, which can provide an experimental basis for research in related fields.
Experimental Study of Gas-Liquid Two-Phase Flow in a Vertical Wellbore with Reciprocating Pumping Rod
Authors: Ma Gaoqiang , Han Guoqing , Shi Junfeng , Xiong Chunming , Zhao Ruidong , Zhang Xihsun 
Published: October 2023

Abstract
For the rod lift system, the up-and-down reciprocating motion of the sucker rod continuously exerts external forces on the fluid in the wellbore, which intensifies the instability of the gas-liquid two-phase flow. At the same time, due to the presence of the sucker rod, the cross-section of the flow channel in the wellbore is changed from a circular to a rod-pipe annulus, making the fluid more susceptible to the sucker rod motion. In order to study the effect of the reciprocating motion of the sucker rod on multiphase flow, an experimental platform was built to study the pressure and flow pattern changes in the wellbore under various gas-to-liquid ratio and lifting parameters, e.g., number of strokes, gas and liquid injection rate. Observed from the experiments, four flow patterns under the reciprocating motion of the sucker rod were identified: bubbly, slug, churn, and annulus flow. It is the relative motion between the rod and the fluid that intensifies the gas-liquid slip effect, and the collision fusion between bubbles is more frequent. However, when the gas injection rate exceeds a certain limit, the influence of sucker rod motion gradually decreases and the flow pattern is not changing. This paper further investigated the pressure distribution in the wellbore with different number of stokes and gas/liquid injection rates. The analyses indicated that the pressure at different test points showed periodic changes with time. Meanwhile, the higher the number of stoke, the more pronounced the periodicity of pressure, and the pressure fluctuation is highly associated with the up-and-down motion of the sucker rod, i.e., the number of strokes is proportional to the frequency and amplitude of pressure fluctuation. At the position of rod coupling, the chance of collision and fusion between bubbles increases and air slug are formed. Based on the experiment data, the drift-flux model (DFM) is modified for multiphase flow in the rod lift wellbore. Because the relative motion between the rod/coupling and the fluid, the presented DFM in this paper has higher prediction accuracy at low and high-volume fraction of gas compared with the literature DFM for a vertical wellbore. This mechanism study not only helps to optimize lift parameters to maximize pumping efficiency, but also provides experimental data in developing or verifying mathematical gas-liquid two-phase flow model for the rod lift system.