bluuebunny/crossref_metadata_2025_split huggingface dataset:
A New Approach Towards Flow Diagnostic in High-Rate Gas Wells
Authors: Marin J. D. , Chacon A. Castro , Almeyda O. , Lopez L. , Quintana J. E. , Gonzalez J. W. , Linares A. J. , Perez J. , Schoepf V. , Abbassi L. 
Published: September 2024

Abstract
High gas rate wells flowing up to 80 MMscfd pose challenges for flow diagnostics. Conventional methods for measuring gas and water holdups, such as local electrical probes, fail in these extreme conditions due to the extremely small droplets and hydrodynamic effects. Approaches based on fluid column density measurements suffer from large inaccuracies due to friction effects. The paper describes the sensor technology and field results from a high gas rate well with small water cut and complex flow regime.
To overcome these challenges, an operating company worked with a service and manufacturing company to improve a compact toolstring capable of delivering reliable flow data (holdups and phase velocity) for phase allocation over an interval with multiple zones and different fluid properties. The toolstring developed is shorter than conventional tools (just over three foot long) and causes minimal flow disturbance. Azimuthal phase holdups and velocities are collocated with one foot away auxiliary measurements of pressure, temperature, MEMS Magnetic Locator (MML) for casing collar detection and depth correlation, tool orientation, and deviation. The flow array sensors consist of triphasic optical probes, conductivity probes, micro-capacitances, Doppler, and wide-range robust micro-spinners.
Segregated flow with water recirculation was observed. The micro-capacitances provided the most reliable source for water holdup while the electrical probes in mist flow, as expected, stopped detecting water at flow speeds of 2 m/s. The triphasic optical probes showed good gas hold up measurements at the whole range of flow velocities in the well and responded to a small water entry in the middle of the perforated zone. All micro-spinners rotated well throughout the survey even at the highest rate. The radar sonde detected water droplets down to micrometer size using the retro diffusion of light electromagnetic signal at a distance from the sensor surface. While the EM radar senses water movement inside the mist flow, the Doppler sensors allowed to monitor movement in the water dominant leg at the well bottom. Thanks to integrating all types of sensors physics, a robust flow diagnostic allowed the operator to understand the water and gas entries, while the conventional sensors could not, and consider remedial actions for water shutoff. The present sensor configuration and tool string can be used as reference for logging in the same field or similar flow conditions.
In order to detect water, two novel sensors were developed: micro-capacitance probes to measure water holdup and electromagnetic radar for measuring flow speed. The standalone radar module operates in high velocity flow and does not require direct contact between droplets and the sensing element, as micrometer size water droplets can be detected with the retro diffusion of light EM signal at a distance from the sensor surface.
Integrated Framework for Proactive Sand Management: Leveraging Offset Well Data, Formation Stability Assessment, and Predictive Sand Transport Simulation
Authors: Vo Nghia Tri , Nguyen Hong Viet , Luong Chi Van 
Published: September 2024

Abstract
This paper addresses the challenge of sand production impacting well productivity. Authors propose a novel, integrated approach for proactive sand management that combines offset well performance analysis, geomechanics, and sand transport modeling. This methodology aims to minimize sand production for enhanced well productivity, develop tailored well designs with appropriate sand control methods for specific reservoir challenges, improve understanding of reservoir dynamics and sand transport mechanisms and optimize well production strategies.
Our approach leverages the following steps:
Offset Well Data Analysis: Production histories, completion types, and reservoir properties of existing offset wells are analyzed to identify factors influencing sand production and successful sand control strategies. Geomechanical Assessment: Separate geomechanical studies are used to assess formation stability under varying drawdown scenarios. This establishes safe operating limits to minimize formation instability and sand mobilization. Tailored Well Design: Based on the understanding of reservoir and sand behavior, well designs are developed with appropriate sand control methods (determined in separate studies) to address the unique challenges of the target reservoir. Production performance analysis: Potential fluid movement between formations is investigated using crossflow analysis techniques. This enhances reservoir understanding and optimizes production strategies. Sand Transport Modeling: Advanced transient simulators are used to build sand transportation models, predict potential sand production and blockage risks for multiple grain sizes and operational scenarios. Proactive measures and targeted interventions are then outlined for these potential situations.
This integrated approach offers a new standard in proactive sand management. It leverages offset well data, promotes a deep understanding of reservoir dynamics, facilitates tailored well design, predicts sand transport, and incorporates crossflow analysis.
This approach distinguishes itself by combining traditionally separate analyses. It integrates offset well analysis, geomechanics, and sand transport modeling for a holistic understanding of sand management challenges. It incorporates crossflow analysis, previously underexplored in sand management, to enhance reservoir understanding and production strategies. It focuses on proactive measures and targeted interventions for sand transport management. By implementing this comprehensive approach, operators can significantly improve well performance and optimize reservoir development.
Assessing Flow Potential Risk in Shallow Zones
Authors: Piazza R. , Netto P. , Grell A. P. , Fernandes L. , Schuck G. 
Published: September 2024

Abstract
Maintaining integrity is a major concern throughout the lifecycle of a well, especially during the decommissioning stage. Regulatory requirements mandate that barriers be established to prevent the flow of fluids to the surface, and that these barriers reconstitute the cap rock above intervals deemed to have flow potential. This can lead to extremely complex projects in scenarios where shallow zones distant from the reservoir are classified as having flow potential. Accurate characterization of shallow zones can have an outsize impact on the costs and operational challenges of the abandonment. Additionally, because decommissioning constraints must already be considered from as early as the drilling stage, these characterizations may influence decisions ranging from well design and completion to the field development project.
Characterizing the flow potential of shallow zones is inherently challenging, due to the scarcity and uncertainty of the data from these intervals. An exceedingly conservative approach can lead to abandonments that are not only costly, but that might also carry unnecessary operational hazards. On the other hand, not being sufficiently conservative increases the risk of an eventual leakage to the environment. Hence, the development and application of a consistent risk-analysis methodology is essential for operators.
The methodology presented is based on an ALARP approach and aims to quantify the likelihood and severity of an eventual outflow of fluid from the well after its abandonment, thus determining the level of risk associated with each interval and allowing for appropriate actions to be taken. The severity classification of a leakage event is based on the characteristics of the fluid present in the interval and on a stochastic estimate of the eventual volume that would flow to surface, supported by an analytical model that couples reservoir and wellbore flow behavior. Meanwhile, the likelihood is defined by the probability that such a leak would occur, based on a set of direct and indirect evidence available, and on the level of confidence associated with the data.
The application of this methodology has proven to be quite robust. It has streamlined the evaluation of individual intervals across various scenarios by providing a systematic approach that different teams can easily and consistently follow and has increased confidence in the decision-making process. Consequently, several recent wells were able to be decommissioned through simpler, safer configurations, and the drilling of several prospective wells was made viable due to less exigent isolation requirements.
Given the uncertainty related to the flow potential of shallow intervals and the consequences of underestimating or overestimating the risks associated with their characterization, it is vital that practical experiences and novel modeling strategies be shared and discussed by the community, to enhance the safety of well operations.
Smart Product to Cure Fluid Losses in Drilling Operations
Authors: Cracolici F. , Minelli M. , Vailati M. , Baretti S. , Iorio V. S. , Poloni R. , Sabatino L. M. F. , Goffredi G. , Valvo L. Lo , Bedogni E. , Alqutt Marwa , Napoleone L. L. 
Published: September 2024

Abstract
The project aims to develop a smart product for losses, different from the traditional approach, to control partial and total fluid losses in drilling operations. The developed smart product for losses is customized to reduce the non-productive time (NPT) and to improve the operation efficiency in compliance with oilfield safety requirements and industry standards.
This smart product for losses was engineered and validated both by operator and chemical provider partner's research technology laboratories, in order to verify the applicability range in water base mud (WBM) and oil base mud (OBM) environmental.
The smart product for losses is a bi-component fluid mixture, consisting of two parts: monomers blend and activator. These monomers and activator mixture show water-like rheological properties and are capable of becoming a stiff solid after a reaction activated by the temperature. The activation temperature can be regulated based on single application needs. This smart product for losses is pumpable throughout the drill string safely and becomes quickly a stiff solid when in contact with the formation temperature, creating a solid barrier in the well with consequent stop of drilling fluid losses.
The bi-component system has been designed with a series of laboratory tests to find the best mixture of monomers and activator. Once the formulation has been fixed, prior to moving on first field trial, confirmatory test campaign has been performed to ensure the proper functioning at the candidate well environmental condition. The first field trial was done in a depleted well ready for Plug & Abandonment, to verify fluid mixability and pumpability with conventional oilfield equipment in a real-life scale and verify proper product setting at well condition. All achievements for the test were satisfying and allowed the project to move to the next step, a test on a well with high probability to face out of total losses scenario during drilling operations. With this second test, the objective was to confirm the reliability of the bi-component system in a loss scenario during the drilling operation. Similar to the first field test, this test while drilling also achieved good results with the confirmation of capability of smart product for losses to properly setting on a open hole well bore condition, confirming the smart product's consistency.
Modeling of Multiphase Flow In Gas-Condensate Wells Under High Gas-Liquid Ratio Conditions and Field Application
Authors: Hong Jiajun , Wang Zhihua , Wang Cong , Zhang Jiuxiang , Qi Xiangdong , Ling Kegang 
Published: September 2024

Abstract
Currently, with continuous innovation of gas-condensate reservoir development technology, the production of gas-condensate and light oil has rapidly increased, making gas-condensate play an important role in the global petroleum industry. However, due to the deeper burial depths of gas-condensate reservoirs under high gas-liquid ratio condition, temperatures and pressures are much higher than conventional reservoirs. At the bottom of the wellbore, the gas-condensate system typically exists in a gaseous state. The retrograde condensation phenomenon is often observed during the production process of such gas-condensate wellbore. Especially when heavy components are present in the gas-condensate well,the appearance of wax particles, and complex multiphase flow characteristics with gas, liquid, and solid phases mixed flow are formed. These complex phase change characteristics of multi-alkanes coupled with multiphase flow patterns may have varying degrees of impact on production operations, from minor to severe.
Based on existing phase equilibrium models of multi-alkanes, this study fully considers wax appearance and dynamic changes in gas-liquid ratio caused by retrograde condensation. By coupling the multiphase flow characteristics of gas-condensate wells with the phase change process of gas-liquid-solid components under high gas-liquid ratio conditions, a mathematical model was established to predict multiphase flow in gas-condensate wells. This model not only reveals the phase change behaviors and wax appearance characteristics in gas-condensate wellbore with high gas-liquid ratio but also determines the critical wellbore depths at which the gas phase transitions to the liquid phase and wax appearance. It reliably predicts the composition of gas-liquid-solid phases at different wellbore depths. As the wellbore depth decreases, phase changes occur in sequence with decreasing molecular weight, appearing liquid and solid phases. The wax particles of solid phase are mainly composed of C33* (C33 to C40)and C25*(C25 to C32), while the liquid phase formed by the retrograde condensation is primarily composed of C17*(C17 to C24)and C9*(C9 to C16).
Additionally, it establishes a general correlation for predicting pressure drop, temperature drop, and wellbore depth in high gas-liquid ratio condensate wells, and the model's error is controlled within a 5% range by validating with actual data. Finally, the model calculation results determined the flow pattern transition process as follows: from single-phase gas flow at the bottom to gas-liquid phases mist flow and gas-liquid-solid phases mist flow towards the wellhead, and in conjunction with the supercritical state of light hydrocarbons to provide an explanation for the relationship between multiphase flow structure and wellbore pressure drop.
Characterization of Cement’s Temporal Mechanical Properties Under Simulated Downhole Conditions
Authors: Meng M. , Frash L. , Carey J. W. , Li W. 
Published: September 2024

Abstract
The evolution of cement mechanical properties is crucial for the performance of zonal isolation and determining the wait-on-cement period. To address this, a triaxial testing facility is developed that directly measures cement static elastic modulus and Poisson’s ratio of cement under in situ conditions. The accuracy of this facility was validated by measuring the bulk modulus of water. To obtain the temporal evolution of cement mechanical properties, an unloading-loading cycle every 30 mins was used from the beginning to the end of the experiment. An amplitude of 10 MPa during cyclic loading guarantees that the cement is in the elastic stage. The theory of poroelasticity was applied to estimate cement elastic modulus and Poisson’s ratio. A 7-day experiment was conducted under axial stress cycling between 40 MPa and 30 MPa, with a confining stressof 25 MPa. The Class G Cement, with a water-cement ratio of 0.4,began to gel after curing for 350 minutes (min), with rapid strength growthoccurring between 400 to 2000 min. After this period, the cement’s elastic modulus stabilized between 47 and 55 Gigapascal (GPa), and its Poisson’s ratio reached 0.35. These values are significantly higher than those obtained from the conventional triaxial compression tests. Overall, our work provides one way to evaluate cement in situ mechanical properties, which can be highly valuable for geothermal and deepwater drilling applications.
Estimating Near-Wellbore Cooling Due to Drilling Circulation and its Effect on Drill Stem Test
Authors: Hasan Abu Rashid , Manikonda Kaushik , Jang Minsoo , Rahman Mohammad Azizur , Hashmi Gibran 
Published: September 2024

Abstract
When drilling oil, gas or geothermal wells, the temperature difference between the wellbore and the formation can have a significant impact on its surroundings. Fluid circulation after drilling to rid the wellbore of drilling mud causes significant cooling around the wellbore near the bottom-hole. Even after shutting the well in, it often takes a long time for this near-wellbore zone to get back to the original formation temperature. This zone of altered temperature around the wellbore can give rise to various phenomena. It may influence wellbore stresses that may cause wellbore instability in high temperature formations that may lead to formation breakdown, or loss of circulation, or even a false kick. It may also play a part during any formation testing procedures carried out right after drilling. In the initial stages of flow after perforation, during clean-up, fluid flows through this cooled near-wellbore zone and enters the wellbore at a lower than undisturbed formation temperature. Any inference about this early fluid’s properties or their flow rates needs to account for the near-wellbore cooling. The estimation of compressible fluid flow rate is further complicated during Drill Stem Tests (DSTs) due to the transient nature of the temperature profile and having to account for multiple fluid entry points. At the start of the production period or when the production rates are changed in multi-rate DSTs, thermal transients take much longer to stabilize than the pressure. Because DSTs are often conducted before the near-wellbore temperature has become stabilized, DSTs are also affected. Thus, estimates of the near-wellbore temperature is often important.
This paper presents a model for estimating near-wellbore zone (NWZ) temperature as a function of radial distance and time. Heat lost (or gained) by this zone due to circulation is used to establish temperature distribution in the affected zone using a line-source solution of the heat diffusivity equation.A recently developed model for circulating fluid temperatures in tubing and annulus for offshore wells allows us to estimate heat transfer from the formation to the circulating fluid in the well.Note that various approaches, including the Horner method, are available to estimate any heat recovery of the affected zone for a well that has been shut-in after circulation. The model allows the computation of fluid flow rates and their entering temperature in the wellbore at early times. These estimates can then be used as inputs in DST analysis for more accurate characterization of the reservoir. Thus, the model impacts the deliverability results and in turn affects project economics. The model is validated using a set of field data.
Unraveling Damage Variables in Hot Dry Rocks: An Optical Investigation of Geothermal Rocks from UTAH FORGE
Authors: Nath F. , Cabezudo E. 
Published: September 2024

Abstract
Geothermal resources are worldwide renowned for their sustainable and clean attributes. The US Department of Energy (DOE) estimates that harnessing only 0.1% of Earth's geothermal energy could support mankind for two million years. Enhanced geothermal systems (EGS) are highly acclaimed for their ability to extract heat from hot, dry rock. However, issues remain in assuring safe drilling and proper fracturing owing to a lack of knowledge of damage factors and fracture sequences, both of which are crucial for regulating crack propagation. Conventional laboratory approaches often fail to capture the nuanced variation seen in HDR. To address this, the present work uses a three-dimensional optical approach called digital image correlation (3D-DIC) to investigate damage factors in HDR.
HDR samples from the DOE UTAH FORGE project's Well 16B (78)-32 are subjected to uniaxial (D 1.5", L 2") and diametrical (D 1.5", L 1") compression using a 100kN precision electro-mechanical load Instron frame at a constant displacement rate of 0.05mm/min. During the uniaxial and diametrical compression studies, a Trilion 3D-DIC image capturing system was used to monitor the samples at a rate of 10 frames per second in a non-contact manner. To monitor deformation during loading, a black-in-white speckle pattern is placed on the specimen. The GOM 3D-DIC system is used to process images, visualize data, and analyze HDR damage variables under various load circumstances.
The findings showed that DIC-generated quantitative full-field strain preliminary maps (tension, compression, and shear) include all sequences involved in the damage process as well as discrete strain localization zones (SLZ). Damage factors are quantified using DIC maps to assess sample damage; the tension-compression ratio ranges between 2% and 8%. The damage evolution process of HDR specimens is divided into four phases that are assessed using damage variables: initial damage stage, linear elastic, elastic-plastic, and plastic damage stage. The damage variable regulates the deterioration of the material's stiffness, resulting in a nonlinear relationship between stress and strain. The damage to the SLZ demonstrates that it is bigger than the entire. The damage was at 65% in the yield stage and 35% in the first two stages. The 3D-DIC findings showed that the sample failed when the overall damage variable reached 0.25-0.35, and the damage in the SLZ region reached 0.8-near unity.
The damage variable in HDR, which indicates fracture progression, is a unique characteristic in geothermal systems. These results have a substantial impact on our capacity to forecast the damage process in EGS. DIC outperforms CT, SEM, and AE methods in test range, cost-effectiveness, accuracy, and full-field monitoring. It improves our knowledge of damage factors in anisotropic and heterogeneous HDR, increases fracturing efficiency, and improves heat extraction from EGS.