bluuebunny/crossref_metadata_2025 huggingface dataset:
Investigation of Fracture Characterization Through the Transport Behavior of Magnetic Nanoemulsions
Authors: Ahmadi Seyedeh Hannaneh , Maaref Sepideh , Ding Boxin , Siadatifar Seyed Emad , Ariza Daniela Mayorga , Bryant Steven L. , Kantzas Apostolos
Published: March 2024

Hydraulic fracturing is a promising way to increase oil recovery in tight reservoirs. The accurate assessment of the expansion of fracture networks within the reservoir is a prominent challenge encountered in hydraulic fracturing operations. To overcome this obstacle, the incorporation of tracer injection along with the fracturing fluids and flowback analysis provides fundamental knowledge for reservoir characterization. Herein, a magnetic Pickering nanoemulsion is introduced as a potential tracer for hydraulic fracturing applications. In this regard, the transportation behavior of this particular Pickering nanoemulsion is a crucial factor for designing and optimizing its implementation in energy, sustainability, and environmental areas. In this study, a polymer-coated iron oxide (Fe3O4) nanoparticle (NP) was synthesized and utilized as a stabilizer to form stable oil-in-water (O/W) nanoemulsions. Two different types of nanoemulsions (with the highest and the lowest stability) were then fabricated with various ratios of polymer shell to Fe3O4 nanoparticle core (3:1 and 0.5:1). Core flooding experiments were then performed in a sandpack to evaluate the stability and retention behavior of the synthesized nanoemulsions in porous media. The nanoemulsion flow profiles were quantitatively monitored by X-ray CT scanning and sandpack magnetic susceptibility experiments. In addition, the density of the nanoemulsion effluents and pressure drop during the whole flooding process were measured to evaluate the most effective nanoemulsion formulation with the lowest retention in the porous media. According to the obtained results, the most stable nanoemulsion formulation with the highest polymer-to-nanoparticle coating ratio (3:1) was transported through the sandpack effortlessly with the lowest retention. The pressure-drop results also showed a gradual increase of pressure during nanoemulsion flooding due to the drag force and higher viscosity of the nanoemulsions compared to water. However, throughout the chase water flooding, the nanoemulsion with the highest stability was displaced piston-like along the sandpack with lower pressure drop, implying lower retention of the nanoemulsion at the higher ratio of polymer to nanoparticle coating.
Investigation of Pore-Scale Evaporative Drying, Salt Precipitation and Crystallization Migration in CO2 Injection Process by a Lab-On-A-Chip System
Authors: Wang Bo , Wang Xiangzeng , Liang Quansheng , Chang Yuanhao , Ma Rui , Lin Zeyu , Lv Xinqian , Li Yishu , Zeng Fanhua
Published: March 2024

In this study, a self-designed microchip system was used to visually study the pore-scale salt crystallization and migration, and a high-performance optical microscope was used to dynamically observe the salt precipitation process and results. The results show that pore-scale salt crystals mainly precipitate in the residual water phase, and mainly present two forms of occurrence, large-grained salt crystals and small-grained aggregated crystals, respectively. In addition to growing in the brine phase, large-grained salt crystals also nucleate and grow at the gas-liquid interface, and the maximum salt crystal size can reach the order of the pore size. This phenomenon was discovered for the first time and has not been mentioned in the existing literature. In addition, this study also observed an interesting phenomenon. The salt crystals formed in the wetting brine film and the brine phase can migrate under the combined influence of displacement pressure and capillary force, and eventually accumulate and precipitate inside the pores. Injection flow rate and salinity have a strong influence on the pore-scale salt crystallization kinetics. There is a critical value for the injection flow rate, and the critical injection rate causes the salt precipitation to be significantly aggravated. Under the same injection flow rate, an increase in salinity leads to an increase in the amount of salt precipitation.
Integrated Characterization of Expanding-Solvent Steam-Assisted Gravity Drainage (ES-SAGD) Processes by Using a Heat-Penetration Criterion within a Unified, Consistent, and Efficient Framework
Authors: Yang Shikai , Yang Daoyong
Published: March 2024

The hybrid solvent-steam injection (e.g., expanding-solvent steam-assisted gravity drainage (ES-SAGD) is the most promising method to enhance heavy oil recovery (EOR); however, it is a quite a challenge to reproduce the experimental measurements and in-situ observations because of the complicated multiphase flow behaviour resulted from the coupled mass and heat transfer. In this work, an integrated technique has been developed and applied for the first time to dynamically and accurately characterize an ES-SAGD process within a unified, consistent, and efficient framework. By taking the competitive impact between heat energy and solvent dissolution, a generalized heat-penetration (HP) criterion has been derived and integrated with a numerical simulator to characterize the dynamics of solvent/steam chamber propagation conditioned to the production profiles during hybrid solvent-steam processes. This generalized HP criterion allows us to not only dynamically calculate temperature profiles beyond a solvent/steam chamber interface (SCI), but also accurately and pragmatically quantify mass and heat transfer inside the diluted oil drainage zone as well as the solvent/steam chamber. Also, comprehensive effects of the thermally sensitive co/counter-current flows are examined with a series of multiphase relative permeabilities. Such an integrated technique has been successfully validated by reproducing the measured solvent/steam chambers in 3D physical ES-SAGD experiments. Good agreements between the simulated and measured production profiles (i.e., injection temperature, pressure, and flow rate) have been made throughout the entire production period. Not only have the measured solvent/steam chambers been reproduced, but also sensitivity analyses have been performed to investigate the influences of multiphase flow behaviour, solvent concentration, and grid dimension. It is found that the diffusion/dispersion coefficients and thermal properties are dependent on temperature and solvent concentrations, competitively affecting the calculated temperature distributions. Moreover, gas-liquid relative permeabilities can impose a significant impact on the SCI moving velocity as well as the oil drainage front. Such an integrated approach considerably reduces the simulation uncertainties and complexities, offering a straightforward and effective means of dynamically reproducing the observed solvent/steam chambers within a unified, consistent, and efficient framework.
Active Magnetic Ranging Solution While Drilling for Geothermal Loop: Test in Low-Conductive Formation
Authors: Husby K. , Hjelstuen M. , Eriksen T. J. , Saasen A. , Ytrehus J. D. , Liberale A. , Koraei M.
Published: March 2024

In the enterprise of creating a geothermal loop deep in a formation it may be necessary to drill an intercept with another well. This intercept has some similarities with the well intercept needed when drilling a relief well in cases of blow out of gas or oil wells. At the same time, it is necessary to avoid colliding with the other well prior to reaching the intercept point. A constant distance may be required to the other well at some well depths. A prototype of a tool for Active Magnetic Ranging While Drilling (AMR) without the use of a wireline operation has been developed to navigate for distance control or intercept. The main scope of the current article is to present the results of a prototype test of this new tool in a test well suitable to simulate geothermal well.

The ranging tool emits a low frequency alternating current into the formation to reach the target well. The current then run down the target well’s casing and back to the well being drilled. This electric current set up a variable magnetic field that is measured by the AMR tool determining the distance to and the direction towards the target well. Hence, the tool facilitates drilling radiator shape multi-lateral well paths. If drilling an intercept at the end of the radiator sections, 10 - 25 wireline runs are needed in each lateral to the target well is intercepted. The present AMR tool is fully integrated in the drill pipe and, thus, all the tripping operations are avoided.

A prototype of an active magnetic ranging tool on the drill pipe has been developed. This tool design is outlined in the paper. The focus is given to performance tests conducted in research wells in Norway. A drill pipe is placed in a vertical well drilled in a gneiss formation. This well simulates a target well. The AMR tool was run in a parallel well and the direction and distance to the nearby target well was measured. The gneiss formation would be a tough formation to drill. However, this formation type is suitable for testing drilling in geothermal well formations. The set-up and the results of this logging operation conducted on a drill pipe is described in detail. It is shown how the direction and distance between the two wells are measured using the tool.
An In-Depth Evaluation of Toe-To-Heel Air Injection Application in a Heavy Oil Reservoir Underlain by Bottom Water. Kerrobert Case
Authors: Turta Alex , Singhal Ashok K. , Islam Mohammad N. , Greaves Malcolm
Published: March 2024

Toe-To-Heel Air Injection (THAI) is an efficient in-situ combustion (ISC) process in which a horizontal producer is located close to the bottom of an oil layer with its toe close to a vertical air injection well. Once initiated, the ISC front propagates from the toe to the heel region of the horizontal section of the producer. THAI provides more control over the direction of the ISC front propagation (guided by the horizontal section of the producer), and it preserves the in-situ upgrading of the oil due to its short-distance oil displacement feature. Because of its controlled gas-liquid segregation, THAI is designed to mitigate the severe override experienced in conventional ISC processes.

The Kerrobert THAI Project represented the second testing of THAI in the field, and it was designed and implemented by Petrobank Energy and Resources ("Petrobank"), based on the THAI patent (US Patent No. 5626191, 1997, Canada Patent No. 2176639, 2000). The patents basically describe two separate well applications: a direct line drive (DLD) configuration and a staggered line drive (SLD) configuration, for which birds-eye views are provided in Figure 1 and Figure 2, respectively. An illustrative cross-section of the process is shown in Figure 3; the start-up region is shown in all these pictures.

The patents indicate that the vertical injector should be perforated high in the oil formation in both cases. The Kerrobert Project was designed to use DLD well configuration, but during the operation, SLD configuration was also tested in a few cases.
Phase Behavior Analysis of Multicomponent Diluent and Bitumen Mixtures: Applications in In-Situ Extraction and Pipeline Transportation
Authors: Khan Mohammad Shah Faisal , Hassanzadeh Hassan
Published: March 2024

This research investigates the phase behavior of multicomponent diluent and bitumen mixtures, providing experimental data essential for bitumen recovery and pipeline transportation. Using a custom-made experimental setup, including a high-pressure and high-temperature rocking PVT cell, densitometer, viscometer, and data acquisition system, the study analyzes homogenous mixtures and liquid-liquid equilibrium (LLE). Thermophysical properties, such as viscosity and density, are measured. The results reveal that a critical volume fraction of 0.7 of the multicomponent solvent studied leads to a phase transition from homogeneity (single-phase liquid) to two distinct liquid phases. Liquid-liquid equilibrium analysis at different solvent concentrations and temperatures demonstrates the significant impact of diluent on bitumen properties. This study addresses a gap in existing experimental data, offering crucial insights into solvent-aided bitumen recovery and pipeline transportation. It contributes to fostering more efficient and sustainable practices in the oil and bitumen industries.
Case Study of Autonomous Inflow Control Devices (AICD) to Control Water Production in Fractured Carbonate Reservoir in Eastern Montana
Authors: McConnell Matt , Jasser Rami , Tappan Jake , Fipke Steven
Published: March 2024

Autonomous Inflow Control Devices (AICD) have been commercially available since 2010 and there are many published case studies of wells in sandstone reservoirs, encompassing a wide variety of water and gas control scenarios. There are, however, relatively few documented studies of AICD for water control in fractured carbonate reservoirs. This paper will discuss and compare two trial wells that were completed with AICD in Eastern Montana in late 2022.

Mission Canyon is a limestone formation of the Mississippian age and is associated with the Williston Basin of the North Central United States. It is composed primarily of oolitic calcarenite consisting of sedimentary carbonate grains. Depending on the grain size, matrix permeability can be relatively low, and a complex network of natural fractures is what dominates fluid flow. These fractures can be good or bad; they can deliver a good oil rate, or they can be direct conduit to the reservoir’s natural bottom-water drive. Consequently, most wells start with 50% water cut and reach 90%+ within a few months. Water volumes can be as high a 3000 barrels of water per day, per well, requiring large-volume pumps and significant water handling & disposal infrastructure. This field trial of AICD technology was designed to reduce water production rates, and then evaluate the impact on additional oil recovery.

The technology tested was an AICV (autonomous inflow control valve) that utilizes the fluid viscosity and density to autonomously restrict water. The AICV devices were installed in two wells; the first was an existing horizontal producer (retrofit installation) and the second was a newly drilled horizontal well. AICV were installed on 3-1/2" liners in the open-hole horizontal section, compartmentalized into stages by swellable packers. Each compartment of the well was approximately 150 ft long and was controlled by a dual AICV flow screen. Nodal analysis predicted a 50% reduction in produced water, with an increase of 20-30% oil rate versus the standard open-hole laterals.

This field study documents the world’s first application of the AICV technology for light oil, water control in a fractured carbonate reservoir. Many valuable lessons were learned on how to best complete and operate the wells. Preliminary results show effective water control, regardless of pressure drawdown. The paper will share production results for each well and attempt to estimate the net effect on oil production and well economics.
Integrating Fracture and Reservoir Modelling to Evaluate Fracture Geometry and Reservoir Performance – A Duvernay Case Study
Authors: Taylor Robert Stewart , Joslin Kevin , Alexander Neal , Jackson Jared
Published: March 2024

Hydraulic fracture modelling and reservoir simulation modelling both have many benefits for understanding the performance of induced fractures and the reservoir. However, these modelling practices are rarely used together. By integrating these workflows, it enables a more comprehensive and accurate understanding of how both primary and complex induced fractures contribute to production. In this study, a Duvernay case history was investigated where fracture and compositional reservoir simulation were both applied as one integrated workflow.

Initially the two workflows were conducted independently. The complete pumping schedule was used in a fracture simulator to predict the number, size, shape, and conductivity of the hydraulic fractures. To properly characterize reservoir flow with a gas-condensate fluid system having complex phase behaviour, a compositional reservoir simulator was required. The reservoir simulation model was history matched against field production data to determine which fractures were contributing to production. Following the history match, new fracture designs were evaluated in the fracture treatment software to better improve cluster and stimulation efficiency. These second- generation optimized fracturing treatment designs were then evaluated in the reservoir model in an iterative process to determine the impact more accurately on production rates, decline curves, and resulting cumulative production.

While fracture modelling provided detailed predictive capability for fracturing treatment design, compositional reservoir production matching contributed a new level of understanding to determine which fractures were contributing to production. The use of reservoir modelling for production matching provided a methodology of reverse engineering the most likely average values for fracture half length, number of effective fractures contributing to flow, and fracture conductivity. A new optimal fracture treatment design was developed by designing it in the fracturing software and evaluating the performance in the reservoir simulator.

This integrated workflow provides insights into limitations of the fracturing treatment design pumped, and what further predictive fracture modelling should be undertaken to further optimize future treatments. The net result provides operators with a new opportunity for increased production and profitability.
Enhancing Performance of Co2-Based CSI Process by Water Flooding and/or Nanoparticle Solution Flooding
Authors: Li Yishu , Du Zhongwei , Wang Bo , Ding Jiasheng , Zeng Fanhua
Published: March 2024

Foamy oil flow is a pivotal aspect of the cyclic solvent injection (CSI) process, yet the influence of water and foam stabilizers, such as nanoparticles, on its efficacy remains insufficiently elucidated. Consequently, a profound comprehension of how waterflooding and nanoparticles impact CSI performance is imperative for advancing oil recovery strategies. This study conducted a meticulously designed experimental investigation to investigate the roles of water and nanoparticles in a CO2-based CSI process. Three distinct tests were executed utilizing a cylindrical sandpack at varying injection pressures. Test 1 entailed a standard CO2-based CSI process for baseline comparison. Test 2 involved a waterflooding process with an injection volume of 1.5 PV, succeeded by a CO2-based CSI process. Test 3 featured a hybrid process comprising the sequence: CSI-waterflooding-CSI-Nanoparticle solution flooding-CSI. Key parameters including injection rate, injection volume, sandpack pressure, production rate, cumulative production, and water cut were meticulously monitored and recorded. Thorough data analytics were then employed to scrutinize the impact of water and nanoparticles, identifying mechanisms for enhancing the CSI process. Laboratory results revealed that the total oil recovery in Test 2 CSI process exceeded that of Test 1 by 7.9%, underscoring the increased efficiency of Test 2. This efficiency was attributed to a 33.2% lower oil saturation after the waterflooding process in Test 2 compared to Test 1. The positive impact of waterflooding on CO2-based CSI processes extended to Test 3, where the oil recovery factor of the CSI phase following waterflooding increased by 7.1% compared to the pre-waterflooding CSI phase. After nanoparticle solution flooding, the subsequent CSI phase yielded an additional 5.9% original oil in place (OOIP), demonstrating the nanoparticles' capacity to enhance foam stability even after multiple second oil recovery (SOR)/ enhanced oil recovery (EOR) processes. As the combined process progressed, the instantaneous gas-oil-ratio increased, facilitated by expanded space for CO2 injection amid heavy oil production. The amalgamated process achieved an impressive total oil recovery factor of 69.5%, more than doubling that of the CSI process in isolation.
Optimizing Completion Design for Delaware Basin Wells with Real-Time Performance Monitoring
Authors: Assem A. I. , Ibrahim A. F. , Sinkey M. , Johnston T. , Marouf S.
Published: March 2024

The performance of shale wells hinges significantly on the Stimulated Reservoir Volume (SRV) generated through hydraulic fracture operations, where the ratio of fluid to proppant per foot is critical for enhancing recovery. Shale well production rates are intricately tied to the Stimulated Rock Volume achieved during fracture treatments, with completion design also playing a pivotal role in optimizing SRV for individual wells.

This paper concentrates on refining completion design for Delaware Basin wells by leveraging real-time performance monitoring. The objective is to enhance overall completion design effectiveness by dynamically adjusting injected fluid volumes based on continuous monitoring of well performance. In the initial completion design for the first well on the pad, a fluid volume of 50 bbl/ft was employed. However, despite monitoring the stimulated fracture surface area, no observed fracture hits during injection and post-stage fall-off analysis suggested the potential for improvement. This led to the hypothesis that increasing the injected fluid volume to 60 bbl/ft could be beneficial.

The adjusted completion design, featuring an increased fluid volume, was implemented in the subsequent well. The stimulated surface area in these wells exceeded the initially calculated surface area in the first well, supporting the hypothesis that the increased fluid volume enhances fracture stimulation. Three months into production, the performance of the second well validated the optimized completion design. This well demonstrated higher production compared to the first, with an increase from 50 bbl/ft to 60 bbl/ft in injected fluid volume. This aligns with surface area estimations, providing tangible evidence of the advantages derived from optimizing completion design through real-time monitoring.

These findings emphasize the significance of considering stimulated surface area in the design process and underscores the crucial role of real-time well performance prediction and the adaptive adjustment of completion design parameters in maximizing production efficiency in the Delaware Basin.
Utilizing CO2 for Energy Extraction from Geothermal Reservoirs in the Baram Basin, Sarawak Using Numerical Reservoir Simulation Based on Analogue Data
Authors: Bataee M. , Rajandran K. V. , Soh M. , Ruvalcaba J. B. , Hamdi Z. , Carter R.
Published: March 2024

This study investigates the sustainable utilization of CO2 for energy extraction from geothermal reservoirs. Geothermal energy is a reliable and renewable source, but its efficiency can be enhanced through innovative approaches. The concept of utilizing CO2 as a working fluid in geothermal systems holds promise due to its favorable thermodynamic properties and potential for CO2 capture and storage. This research aims to explore the feasibility and benefits of using CO2 for energy extraction from geothermal reservoirs. The study combines theoretical modeling and numerical simulations to assess the performance of CO2-based geothermal systems. A conceptual framework is developed, considering the thermodynamic behavior of CO2 and its interactions with the subsurface reservoir. The simulations involve reservoir characterization, fluid flow analysis, and heat transfer calculations, taking into account various operational parameters and system configurations. The results demonstrate the potential of utilizing CO2 for energy extraction from geothermal reservoirs. The simulations reveal enhanced heat transfer efficiency and increased power generation when compared to traditional geothermal systems. The utilization of CO2 as a working fluid facilitates higher thermal efficiencies, lower greenhouse gas emissions, and improved overall system performance. The results also highlight the importance of proper reservoir characterization and operational optimization for maximizing energy extraction potential. The findings of this study emphasize the sustainable and efficient utilization of CO2 for energy extraction in geothermal systems. By employing CO2 as a working fluid, geothermal power generation can be significantly enhanced, contributing to a more sustainable and carbon-neutral energy sector. The outcomes of this research provide insights into the technical feasibility and environmental advantages of CO2-based geothermal systems, serving as a basis for further development and implementation of this innovative approach. The study contributes to the ongoing efforts in harnessing renewable energy sources and reducing carbon emissions, advancing the field of geothermal energy and promoting a sustainable energy transition.
Analysis of Energy-Economic Dynamics in Canadian Provinces: Insights from Data Analytics
Authors: Gbakon K. , Ajienka J. A. , Iledare O. , Gogo J.
Published: March 2024

This paper conducts study of the relationship between end-use energy demand and economic growth as indicated by the Gross Domestic Product (GDP) on a province-level within Canada. There is abundant literature investigating the direction of causality between energy use and economic growth. However, these studies tend to focus on country units or groupings of countries. Additionally, the direction of causality between energy and economic growth has yielded mixed results, which depend on the econometric methods used, the time period, and the inclusion of other economic growth/productivity factors, such as labour and capital. The contribution which this paper seeks to make is to determine the relationship between GDP and energy use within the sub-national units of Canada. This is especially important to help shape the broader conversation about the potential distributional impact of climate change policies on the economic well-being of the sub-nationals of Canada. This paper utilizes the well-known Cobb – Douglas functional form to examine the relationship between inputs, end-use energy demand, and output, defined as GDP for the provinces. Population, End Use Energy Demand and provincial level GDP time series data from 1995 to 2021 are obtained from StatsCan. Our descriptive data analysis revealed that the highly ranked provinces by growth rate of energy use per capita were not necessarily top ranking by GDP per capita growth rate. Taken together, since year 2000, 10 of out of Canada’s 13 provinces and territories have achieved growth in GDP per capita while reducing their Energy use per capita. Additionally, Granger causality showed broadly that the sub-nationals of Canada can be classed majorly as either having neutral relationship between energy and economic growth (46%) or are in the category where economic growth drives the energy use per capita (39%).
Prediction of Mineralogical Composition in Heterogeneous Unconventional Reservoirs: Comparisons Between Data-Driven and Chemistry-Based Models
Authors: Yang Zhengru , Ghanizadeh Amin , Younis Adnan , Clarkson Christopher R.
Published: March 2024

Prediction of mineralogical compositions along multi-fractured horizontal wells (MFHWs) using indirect methods, for the purpose of characterizing lithological and rock brittleness heterogeneity, is appealing due to the challenges associated with direct mineralogical evaluation. This study aims to 1) develop predictive machine learning models for indirect estimation of mineralogical compositions from elemental compositions, 2) compare mineralogical compositions obtained from data-driven and chemistry-based approaches, and 3) provide practical recommendations for fine-tuning and training of data-driven models.

Leveraging recent advances in deep learning, an attention-based gated recurrent unit (AttnGRU) with a "feature extractor-post processor" architecture was developed for predicting compositions of ten primary minerals based on elemental data. For comparison, classic regression-based and ensemble learning models including support vector regression (SVR), random forest (RF), and a feedforward neuron network (FFNN) were utilized. Data-driven models were trained and tested using XRD data measured on 217 samples from the Montney Formation, and the outcomes were compared to those derived from stoichiometric material balance equations (a previously-developed chemistry-based model) to evaluate the effectiveness and capabilities of different predictive approaches.

The data-driven models consistently outperformed the chemistry-based method with significantly lower mean absolute error (MAE) and higher R2. The predictive performance order was FFNN ≥ AttnGRU > RF > SVR >> chemistry-based model, with MAE = 1.05, 1.09, 1.24, 1.35, and 2.46 wt.%, respectively. Importantly, FFNN, AttnGRU and RF offered more accurate predictions of chlorite and illite, which are known to negatively affect reservoir quality. This indicates the superior performance of the three models for reservoir characterization applications. Furthermore, AttnGRU exhibited greater robustness than the other two models, with less sensitivity to overfitting issues. Data-driven models displayed different levels of performance when decreasing training dataset size. It is recommended that, in order to achieve reasonable predictions for the studied reservoir with data-driven approaches, more than 50 training samples be used. It is further observed that data-driven models exhibited limited predictive capability (MAEs ranging from 3.02-3.45 wt.%) when applied to a synthetic "global dataset" comprised of samples from various formations.

Through the comparison of multiple independent datasets (XRF-derived chemistry-based, XRF-derived data-driven, XRD) collected on identical samples, this work highlights the strengths, limitations, and capabilities of different machine learning techniques for along-well estimation of mineralogical composition to assist with reservoir characterization.
Correlating Flow Station Parameters with Oil Wells Performance
Authors: AlAklubi Sultan. A.
Published: March 2024

Offshore production system assessment is very important to maintain and optimize wells performance including ESP, gas lift, natural flow wells, flow line network and de-bottlenecking. The oil production gain from optimization will add great value in maintaining production targets and increase the Maximum Sustained Capacity (MSC) which is the maximum production rate can be produced for stable period within a notice of not more than two months. Offshore optimization includes new facilities such as flow stations, gas lift capacity, introducing new ESP wells, laying down new flow lines and additional transmission lines. Production optimization changes warrant an update and reassessment of the production model used for optimization and de-bottleneck studies including the review and evaluation of the existing well & network models to develop a clear strategy and to update the production model with optimization. The optimal lifting rate according to the well level can be determined by varying the gas lifting rate and comparing its rate of change with the minimum economic rate of change which can be obtained during the ability tests for each well considering changing the gas lift injection rate to sense the impact on the production rate with the best increment to get within the given gas injection rate.

In order to assist oil and gas field workers in daily activities and to optimize the time they spent checking and opening closed wells which is a tedious job especially during rough sea conditions and when there is no available means of transportation, a new way of tracking wells production throughout the flow lines pressure feeding the flow station are presented and examined in order to focus on some areas to regain the production loss due to wells shut in suffering from the back pressure exerted by other wells on the stream. Gathering data from several flow lines to build a database which will be much appreciated especially for offshore fields where there is no Supervisory Control and Data Acquisition "SCADA" Units during rough sea conditions and in emergency cases to overcome production loss.
Digitalizing the Management of Electric Submersible Pump Failures Through Failure Prevention and Post-Mortem Analysis Tools
Authors: Ellsworth Michael , Joseph Rejish , Hematillake Dylan , Diaz-Goano Carolina
Published: March 2024

The replacement and maintenance of Electric Submersible Pumps (ESP) represents a significant operating expense for any in-situ Oil Sands operation. The goal at Suncor's in-situ operations is to effectively and efficiently manage ESP failures to lower costs, maintain production, reduce carbon emissions, and contribute to safe operations. This goal is in part, accomplished through a collection of software tools that automate and enhance Production Engineering workflows related to the management of over 300 ESPs. An overview of the overall digitalization effort, including information about the development and rationale behind the centralized ESP information and analytics database, various failure prediction tools and anomaly detection methodologies, and the application that delivers these solutions is discussed. The estimated impact of this effort is measured through accuracy. The ideas behind the effort have, both directly and indirectly, contributed to the increase in ESP run life, the decrease in ESP replacement time, the decrease in person-hours per ESP required for management, the increase in safe operations, and the increase to general well availability.
How to Sustainably Improve Production Recovery from Existing Wells
Authors: Moen E. , Antonsen R. , Ejofodomi E. A.
Published: March 2024

In today's oil and gas landscape, production recovery from existing wells remains a pertinent challenge. The ever-increasing demand for hydrocarbons and the emphasis on optimized output have led to the endeavor of maximizing production from established wells. However, despite technological advancements, a significant proportion of these wells underperform, either due to inherent issues, such as formation damage, or a decline in reservoir pressure over time. Traditional methods like bullheading chemicals from the surface have struggled to consistently deliver efficient and sustained solutions. This pressing issue has prompted a shift toward innovative methodologies to restore and sustain productivity in underperforming wells. The oil and gas industry requires robust and sustainable techniques that can efficiently address these challenges, optimizing the productivity of existing wells.

This paper presents a novel, data-driven process that uses a downhole, hydraulically activated system to restore and sustain productivity of sub-par producing oil and gas wells. The paper details the steps required to identify and restore the productivity of underperforming wells. Results are compared with traditional solutions based on bull heading chemical treatments from surface.
Integrated Downhole-Measurement-Enabled Coiled Tubing and Mechanical Wireline Recovery of E-Line Cable in a Live, Sour Gas Well
Authors: Villagrana C. , Abouganem A. , Afsal A. M. , Al-Dahhan M. , Delaune J. , Tapia W. R. , Amri M.
Published: March 2024

This study details a complex wire recovery operation in a live well that involved transitioning from coiled tubing (CT) to mechanical wireline (MWL), in both slickline [MA1]or braided line, to retrieve the wire in good condition and later hand it over to an electrical wireline (e-line) unit to spool it onto a drum. The operation was carried out on a live, sour gas well, demanding a unique setup and emphasizing safety. Two successful recovery operations removed a significant amount of e-line left in the well plus the upper section of the e-line bottomhole assembly (BHA) while safely pushing the lower section of the e-line BHA to the bottom of the well. An integrated, multipurpose pressure control equipment (PCE) stack provided safety and redundancy, facilitating retrieval with both CT and MWL. The PCE stack design proved robust, enabling recovery without killing the well. Notably, the operation seamlessly integrated CT, MWL, e-line, and a stimulation vessel, all utilizing the same PCE. A significant challenge involved the handover of the recovered e-line from CT to MWL, requiring careful coordination and movement to prevent stripping the retrieved e-line inside the wire-line valve rams and the risk of gas leaks. Innovatively, this operation marked the first use of downhole measurements for wire recovery alongside the application of jars and impact hammers while pumping on the backside of the coiled tubing, a pioneering approach in this context of live-well e-line recovery. Downhole measurements, particularly tension and compression readouts, aided decision-making, reducing the need for reruns. Furthermore, a downhole camera captured changes in the e-line and BHA. Overall, this operation represents an innovative achievement in wire recovery from live, sour gas wells.
Flowback Three-Phase Flowmeter Implementation for Post-Fracturing Cleanouts: A Case Study from Argentina
Authors: Mirande J. M. , Vassallo J. , Mambriani P. , Gonzalez C. , Fajardo E. , Vecchietti M. , Krasuk R. , Misonischnik A.
Published: March 2024

Unconventional horizontal wells completed with plug-and-perf fracturing techniques require coiled tubing (CT) to clean out the well before it is put into production. To remove proppant and plug debris, water is pumped into the wellbore and flowed back to the surface through the annular section between the CT and the production casing. This study describes implementation and impact of a three-phase flowmeter to measure the return rate and detect proppant and gas in real time.

During CT post-fracturing cleanouts, fluid return rate is critical to monitor because the annular fluid velocity that carries solids out of the well is proportional to it. In addition, wells in Argentina must be kept in a near-balanced condition to avoid producing gas from the well. Fluid return rates used to be measured with an ultrasonic flowmeter, which experienced signal loss when there was more than 5% sand or gas in the fluid, making it unreliable for this workscope. A three-phase flowmeter was therefore implemented to achieve high-frequency and real-time measurements of water, proppant, and gas at the surface.

Implementation of the three-phase flowmeter allowed cleanout optimizations without sacrificing operational safety. Having a precise and continuous measurement permitted the variation of the flowback choke strategy, increasing the return rate to a value closer to the pumping rate by 0.1 bbl/min without affecting the well balance condition. During the execution of the first four-well pad after this new flowmeter was implemented, analysis of the sand flow rate measurement showed that the wells were already clean when the CT had to be pulled out of hole (POOH) after reaching total depth, as only traces of sand were detected during this part of the operation. With this information, the job procedure was optimized by increasing the horizontal section POOH speed from 6 m/min to 12 m/min, if sand was not detected at surface. It also prevented pumping gel pills. This represented a 10% reduction in the total operating time per well and a 25% reduction in xanthan gel consumption in the next completed pad.

This is the first time that a three-phase flowmeter has been implemented for post-fracturing cleanouts in Argentina Vaca Muerta operations. The increase in the precision of surface measurements means a more controlled cleanout strategy, during which flowback is evaluated in real time and the operational program can be optimized. Poor flowback control is a known contributing factor to stuck pipe incidents. This technology plays a critical role in addressing one of the major risks during CT operations.
Challenges and Solutions of Concentric Coiled Tubing Fishing
Authors: Rahimov K. , Nicol S.
Published: March 2024

Concentric coiled tubing technology has many applications for well intervention activities ranging from wellbore cleanout to well unloading and delivering multiple chemicals downhole via separate conduits. Technology historically developed for ultra low bottom hole pressure applications but currently utilization of it was expanded to wellbores with positive wellhead pressure. Concentric Coiled tubing string present similar risk and challenges as Conventional CT. Stuck in hole situation is one of the most notorious situations that requires very close attention and detailed contingency recovery planning. Unlike single pipe recovery where industry has very well-established guidelines and expertise, concentric pipe technology historically lacked both detailed planning and recovery experience. This paper details out the engineering design to address recovery of the CCT. Paper highlights stages requiring for the successful project delivery, step by step guideline and lists out purpose build equipment. Although proposed engineering solutions was not implemented due to the contingency nature, nevertheless careful approach and detailed engineering, risk assessment methods used in developing precise guidelines provides very good resource into existing industry challenge.
Successful Selective Fractures in a Horizontal Well Demonstrate the Effectiveness of an Abrasive Jetting and Stimulation Process in Mexico
Authors: Fontana Cristian , Menconi Federico , Medina Eber , Lugo Ramiro , Perez Raul
Published: March 2024

This study delves into the implementation of an integrated completion strategy for a horizontal infill well within a gas reservoir, with a primary focus on enhancing hydrocarbon recovery. The first lateral well in the field served as a testing ground for the combined utilization of Coiled Tubing (CT) and hydraulic fracturing services aimed at optimizing completion strategies and increasing adaptability in the presence of potentially drained zones along the horizontal section.

The 1.75-inch CT facilitated a rigless operation, with a calibration run ensuring tool passage through potential restrictions, leading to subsequent Abrasive Jetting (AJ) and hydraulic fracturing operations. Grounded in the well's established petrophysical and structural model, a thoughtful selection of depth facilitated the placement of a bridge plug, with Abrasive Jetting (AJ) establishing effective wellbore-reservoir communication. Diagnostic Fracture Injection Tests (DFIT) were then conducted iteratively to assess the interaction of the infill well with undrained areas.

The application of pinpoint stimulation technology demonstrated its capacity to induce fractures through a minimal number of holes, allowing for increased control over initiation sites and improved fracture height coverage. This approach enhances well productivity by increasing the fracture area in contact with the formation. Practicality and cost-effectiveness were validated using CT for various well-intervention procedures, complemented by Abrasive Jetting (AJ) assisted fracturing to minimize fracture entry friction.

The multi-stage operation revealed successful drainage of two zones during the intervention. The acquisition of reservoir data for simulation purposes was pivotal in shaping future field development plans and strategically placing additional lateral wells to optimize recovery factors.

To maximize hydrocarbon recovery and minimize costs, the AJ process and hydraulic fracturing techniques must be carefully optimized for economic feasibility. Reservoir simulations are employed to refine treatments for future projects, leveraging insights from pressure profiles and interactions with offset wells. The lessons learned from this well provide valuable insights for upcoming lateral infill wells, contributing to the continual improvement of execution methodologies.

This first infill well not only validated the hypothesis that reserves persist beyond the drainage radius of previous wells but also demonstrated a doubling of expected production levels. The success of this endeavor underscores the potential advancements in hydrocarbon recovery techniques, with implications extending beyond commercial interests to contribute to the broader understanding of reservoir dynamics and optimal well completion strategies.
Restoring Production Via Non-Rig Deployed Wireline Technology
Authors: Diwaku W. J. , Sambo H. , Sonhi J. M. , Saadi A. Ahmed , Wallach M.
Published: March 2024

Objectives/Scope: This paper details the challenges faced and the solutions deployed to restore production following failure of a formation isolation valve (FIV).

Methods, Procedures, Process: The FIV was installed to isolate the reservoir during the deployment of the Upper Completion. Once the wellhead, tree, and flowlines were hooked up, several attempts were made to open the valve to initiate production. Despite the planned pressure cycles being applied, the FIV did not open. It was suspected that there was fill/debris on top of the valve preventing its hydraulic activation. The failure of the FIV, and associated lost production, drove the team to develop a remedial intervention plan. The Operator and Business Partner team evaluated multiple alternatives before selecting a combined slickline and electric line tractor-deployed solution. The plan included a drift run to determine the wellbore condition above the FIV, followed by a cleanout run and the milling of the FIV Inconel ball-valve. Due to the high hole angle, a tractor was required to apply weight on the mill bit.

Results, Observations, Conclusions: After the removal of the wellbore debris using a slickline bailer and a suction tool deployed with electric line (EL), a tractor milling assembly was deployed that successfully milled through the FIV ball-valve. The successful milling operation saved approximately $30MM in Major Rig Work Over cost by bringing the well back to production levels in accordance with the pre-drill estimates.

Novel/Additive Information: This paper describes the process followed to design an optimal intervention plan, and the detailed planning and operational steps. The optimal engineered solution coupled with operational discipline during execution successfully brought the well back to production, minimizing the lost production cost while avoiding a costly rig-based intervention.

This paper also highlights the novel technologies utilized, the milling BHA configuration, specific lessons learned, and best practices recorded during the execution.