bluuebunny/crossref_metadata_2025_split huggingface dataset:
Investigation of Gas Behaviors in Caprock for Understanding Gas Leakage During Underground Hydrogen Storage
Authors: Chang Qiuhao , Dempsey David , Huang Liangliang 
Published: October 2024

Abstract
Given their efficient gas seals, depleted hydrocarbon reservoirs are one of the most promising underground porous media for large-scale storage of hydrogen. However, H2 has a smaller molecular mass/size which could contribute to a higher rate of molecular diffusion through the caprock, leading to losses during the storage process. Hence, understanding the behaviors of H2in the pores of caprock is a prerequisite for the application of hydrogen storage in depleted hydrocarbon reservoir. In this study, the adsorption and self-diffusion of H2 and cushion gases of CH4/N2 were studied in quartz nanopores under a geological condition of 343 K and 15 MPa via molecular dynamics simulations. The results show that adsorption onto the pore wall occurred for all three gases. Using competitive adsorption analyses, we find that the quartz pore wall likely prefers to adsorb CH4 rather than H2 and N2. In nanopores with only 1 nm width, all the gas in the pore space is in an adsorption status. However, with a larger pore width such as 5 or 10 nm, part of the gas would be in a free gas condition. Due to the molecular weight, compared with CH4 and N2, H2 has the largest self-diffusion in the nanopores. Moreover, the effect of pore width on gas self-diffusion was observed. As the pore width decreased, the gas self-diffusion decreased. The goal of this study is to provide a deeper insight into gas behavior in the caprock and explore mechanisms of H2 leakage through the caprock.
The Field Application of Separated Zone Oil Production Technology Based on Electromagnetic Coupling Principle in Daqing Oilfield
Authors: Liao Chenglong , Yang Qinghai , Jia Deli , Pei Xiaohan , Yu Yang , Du Kai , Yu Chuan , Zhang Wei 
Published: October 2024

Abstract
Separated zone oil production technology plays a crucial role in resolving interlayer and planar conflicts, facilitating the comprehensive development of middle and low permeability layers, reducing ineffective water circulation, and optimizing residual oil recovery during the high water content phase in oilfields. The developed intelligent separated zone oil production technology, grounded in electromagnetic coupling principles, establishes a reliable downhole channel for transmitting power and data. This innovation obviates the need to retrieve the allocation pipe string during routine pump inspections, thereby extending the operational lifespan of intelligent production allocators (IPAs) and lowering operational costs.
This paper presents the field application of electromagnetic coupling-based intelligent separated zone oil production technology in the Daqing oilfield. Currently deployed in four wells, this technology enables real-time monitoring of downhole temperature, pressure, and flow rates, facilitates regulation of zonal fluid production, and offers dynamic insights into various oil production strategies, including multi-layer combined production and single-layer rotational production. Experimental results from a single production rotation test illustrate significant operational outcomes. Following the adjustment of Test Well A from combined to single-layer production (Layer II), daily fluid production decreased from 21.11 t/d to 16.52 t/d, while daily oil production increased from 0.93 t/d to 1.05 t/d, and the average water content decreased from 95.64% to 93.66%. Pressure recovery tests conducted over three consecutive days in Test Well B, during pumping cessation, provided essential data for calculating reservoir parameters such as permeability and porosity. Moreover, repeated docking and separation tests between production and allocation pipe strings were successfully executed. After experiencing pump leakage 23 days into normal production, Test Well A underwent pump replacement and subsequent reinstallation of the production pipe string. Results confirmed successful docking of the downhole electromagnetic coupling device (DECD), ensuring system functionality.
The successful implementation of this technology in Daqing oilfield underscores its suitability for pump inspection operations, high communication reliability, and extended operational life. This technological advancement not only addresses interlayer challenges in oil wells but also enhances reservoir understanding, promising widespread application prospects.
Feasibility Assessment of Symbiotic Processes Between Hydrogen and CO2 Storage in Coal Seams of Various Ranks
Authors: Jiang Chuanzhong , Liu Jishan , Elsworth Derek 
Published: October 2024

Abstract
Carbon dioxide (CO2) and hydrogen (H2) can be symbiotically stored in coal seams, as an effective method for storing H2 to facilitate the transition from fossil-based energy systems to renewable sources and for sequestering growing amounts of captured CO2 to meet carbon neutrality goals. The key challenge in this process lies in determining the interactions between different fluid components and the interactions between fluids and coal rocks, a typical dual-porosity medium.
This research first derives governing equations to depict the flow behavior of multi-component gases in coal fracture and matrix. The effect of unconventional effective stress (UES) on reservoir deformation in the presence of multicomponent gases are also characterized by control equations. Then the UES-dependent porosity and permeability models were developed to explicitly quantify such interactions. A fully coupled numerical reservoir model was established to characterize the reservoir response when H2 and CO2 are symbiotic stored. We subsequently validate the model through experimental data on the flow of multicomponent gases in coal seams, and then use this model to simulate the cyclic operations of such a symbiotic storage process in coal seams.
The model results for cyclic injection and production of reservoirs support the symbiotic storage of H2 and CO2 in coal seams. The main conclusions are: 1. The injection of cushion CO2 increases reservoir pressure and prevent a significant amount of H2 waste; 2. Under the gas stripping effect, CO2 desorbs from the matrix and transfers into the fracture system and then mix with H2. This mixing phenomenon becomes increasingly pronounced with the progression of injection and production cycles, leading to a gradual decrease in the purity of the withdrawn H2; 3. The reservoir permeability increases during H2 injection and decreases during H2 recovery; 4. The larger the adsorption strain constant of H2, the greater the corresponding fictitious stress, resulting in smaller fluctuations in reservoir permeability during the injection and production processes; 5. Low-rank coal seams exhibit the best H2 injectivity and productivity performance, while high-rank coal seams have the highest unit storage capacity for H2 and CO2.
The results demonstrate that this model can be used to characterize the interaction between working gas and cushion gas, as well as between fluids and reservoir rocks. This research also proofs the feasibility of symbiotic storage of H2 and CO2 in coal seams.
New Understanding of Non-Uniform Extension Mechanism of Horizontal Fractures in Shallow Hypertonic Reservoirs and Research on Main Controlling Factors
Authors: Qiao Yan , Zhang Yang , Bai Jie , Shang Litao , Wei Dongya , Hu Xuhui , Ren Guangcong , Bai Haoli 
Published: October 2024

Abstract
The Changyuan block of Daqing oilfield in China has a shallow reservoir depth (&lt;1000m), high permeability (&gt;100mD), is in the late stage of development, and has a high moisture content (&gt;95%). Currently, fracturing has now been used to reduce water content and enhance production. Microseismic monitoring indicated that the fracturing produced non-uniformly expanding horizontal fractures. Current studies provide little information on the mechanism and main controlling factors of non-uniform extension of such horizontal fractures.
In this paper, we proposed the expansion pattern index to characterize the horizontal fracture expansion, and the influence factor to characterize the influence size of each factor. Based on FracMan and other software, we investigated the mechanism of influencing horizontal fracture formation and non-uniform expansion mechanism, and then clarified the horizontal fracture expansion law and the main controlling factors through the changes of different geological factors and engineering factors.
The study results show that horizontal fractures will be formed when the horizontal maximum principal stress &gt; horizontal minimum principal stress ≥ vertical stress in the reservoir. The extension direction of horizontal fractures will be along the direction of large fracture initiation stress difference (Fracture initiation stress difference is the difference between horizontal minimum principal stress and vertical stress). Horizontal fracture extension is mainly affected by the net pressure of construction, plugging distance, pumping scale, the fracture initiation stress difference and the non-homogeneity of the fracture initiation stress difference. The oil production after fracturing is mainly affected by the net pressure, oil saturation, pumping scale, plugging distance and formation pressure. With the increase of pumping scale, the horizontal fracture inflow capacity increases, the length-short axis ratio increases, and the cumulative oil production increases; with the increase of fracture initiation stress difference non-homogeneity, the horizontal fracture inflow capacity increases, the length-short axis ratio of fracture area increases, and the cumulative oil production increases. The microseismic monitoring results of two wells show that the horizontal fracture extension correlates well with the microseismic response, which verifies the correctness of the results of this study.
In this study, we found for the first time the law of non-uniform extension of horizontal fractures in shallow hypertonic reservoirs, which provides a reference for the design of the later block development program and the formulation of reservoir reforming process.
Enhancing Knowledge Exchange to Improve Performance in a Drilling & Well Portfolio on the Norwegian Continental Shelf
Authors: Akhmetova O. , Hansford P. A. , Labrousse S. , Tharavaj F. 
Published: October 2024

Abstract
This paper aims at presenting the tool and the set of methods developed to enhance knowledge exchange across dispersed drilling and well teams working for various projects on the Norwegian Continental Shelf (NCS). This solution has a low threshold for entries, and it fills the gap between isolated project knowledge and high-level corporate project management solutions. The goal is to enhance knowledge sharing to improve performance.
Four principles are followed: (1) A digital ecosystem that facilitates the knowledge exchange process is created. It includes a web application compatible with laptop and mobile usage, storage space, access and notification management, dashboards. (2) Metadata associated with entries are compatible with metadata used in other business systems. (3) Knowledge is classified along three different levels: experience, lesson learned, best practice. This enhances systematization and aggregation of insights. (4) A process supports the capture and the treatment of entries. It ensures content is reviewed, a digest is presented regularly, and value is extracted.
The platform was run with the sole involvement of project engineers for one year. This first step was aimed at populating the database, developing workflows and adjusting hardware. During the second year, the field population was involved. Work processes were formalized. As population of the database continues, a second phase has now started where value creation is the focus with two main goals: (1) Identify areas that require deeper engineering studies. (2) Facilitate an exchange of local best practices. The next step is to leverage on machine learning and natural language processing technologies. Specifically, the team is now working on how to improve the identifications of connections between contents: single entries that may appear insignificant, once connected to others, show the development of weak signals that need to be addressed. The solution proves to be working, it is stable and fully scalable. After two years, the objectives are deemed successfully achieved: experience from the ground is gathered across projects; it is treated via formal processes before being made available to all projects of the company on the NCS. Finally, while performance increased, other units expressed interest in deploying the solution. In response, the tool was recently launched at a global level to simplify and enrich knowledge sharing between integrated projects.
With this paper, we show an example of a cross-project knowledge sharing solution which builds on readily available digital tools. Its low-threshold mindset and the workflows developed enable detection and treatment of weak signals. The solution is a knowledge exchange tool tailored to the field which compliments higher-level corporate solutions with the goal of contributing to a relentless increase in performance.
The Anisotropic Horizontal Stress Estimated Using Well Logs Sonic Data in Deep Longmaxi Shales
Authors: Jia Lichun , Lu Dengyun , Xu Wen 
Published: October 2024

Abstract
It is necessary to understand the geomechanical characteristics of deep Longmaxi shale for safety drilling and hydraulic fracturing. The horizontal stress in shale formations estimated using the vertical transverse isotropy (VTI) model requires five independent elastic stiffness coefficients. From velocity measurements, the five elastic stiffnesses can be obtained from five velocities with three plug samples at 0°, 90°, and 45° direction. But for well-log-based methods, only three out of five stiffness coefficients (C33, C44, and C66) can be estimated from acoustic well logs. To obtain remaining two stiffnesses C11 and C13, the empirical models such as the ANNIE, modified ANNIE (M-ANNIE) models are needed in well-log-based methods. On the other hand, the Biot's poroelastic parameter also exhibits anisotropy, the vertical αv and horizontal αh, respectively, which are not equal and neither is equal to 1. In addition, the formation temperature of deep shale is higher than that of shallow shale formation, which would have an effect on the horizontal stress prediction.
Here, this paper estimates the anisotropic horizontal stress using well logs sonic data in a well of deep Longmaxi shales with consideration of poroelastic effect and temperature. Firstly, a series of ultrasonic velocity measurements and static triaxial tests are performed on core plugs of deep Longmaxi shale for obtaining correlations between the dynamic and static elastic properties. Then the well log-based as well as laboratory measurements are used to predict depth-by-depth horizontal stresses. The results show that the static stiffness coefficients are smaller than their corresponding dynamic results but the static Biot's coefficient is higher than dynamic value. And there are good linear regression correlations between above dynamic and static parameters. In the evaluation of log-based models, the ANNIE model is inapplicable here because ratio of νv/νh is not always greater than 1 while the M-ANNIE model improves the prediction of C13, which demonstrate that M-ANNIE model is applicable to shale. In the prediction of horizontal stresses, one hand the relative error significantly decreases after using static parameters, on the other hand the isotropic model underestimates the horizontal stresses compared with VTI model. The Biot's coefficient has a significant impact on predicting horizontal stresses while the effect of thermal stress on horizontal stress is extremely small. The outcomes of this work can potentially improve predictions of elastic properties and horizontal stresses for geomechanical elastic model analysis in anisotropic deep Longmaxi formation.
Bionic Surface Textured Stator for Deep/Ultra-Deep Well Oil Production Progressing Cavity Pump
Authors: Shi Bairu , Yang Qinghai , Hao Zhongxian , Wei Songbo , Fu Tao 
Published: October 2024

Progressing cavity pump (PCP) are characterized by their simple structure, high transmission efficiency, and broad adaptability. They have been used in drilling and oil extraction engineering since the 1980s and have now developed into one of the most important lifting equipment in oil production [1, 2]. Currently, there are more than 11,000 ground-driven screw pump wells in China, with an average pump inspection cycle of about 700 days.
PCP is composed of a metal rotor and a rubber stator, during the operation of the PCP, there is continuous contact and friction between the rubber stator and rotor, which causes wear on the rubber stator. According to the failure statistics on the oilfield site, the wear of the stator and rotor is one of the main reasons affecting the performance and service life of screw pumps, accounting for approximately 30% of total failures. At present, there is no effective solution for the wear of the rubber stator, so it is necessary to carry out research on lubrication, wear reduction, and resistance reduction of the stator and rotor of the PCP.
In recent years, bionic surface texturing technology, as an effective means to reduce friction, wear, and improve the load-bearing capacity of the friction pair's liquid film, has attracted widespread attention from domestic and foreign tribologists. The excellent characteristics of bionic non-smooth surfaces such as detachment, wear reduction, and resistance reduction have been verified and applied in many engineering fields [3–5].
Geomechanical Risk Assessment of Injection Test for a CCS Site Appraisal, Offshore Northern Territory
Authors: Asadi Sadegh , Khaksar Abbas , White Adrian , Coelho Guil , Rahmanseresht Raed 
Published: October 2024

Abstract
In the context of Carbon Capture and Storage (CCS) site appraisal procedures, the assessment of geomechanical risks associated with injection tests is important. Assessments can calculate injection pressure thresholds and guard against formation fracturing and solids production during fall-off tests or due to unplanned shut-in occurrences.
The Bonaparte CCS project (West Peron), situated northeast of the Petrel Field, offshore Northern Territory, serves as a pertinent case. Two vertical appraisal wells are included in the appraisal work scope, complemented by an extensive data acquisition program. The primary scope of appraisal drilling is to fully characterise the storage site, focusing on confirming the storage reservoir and cap rock continuity and properties along with the assessment of matrix injectivity within the storage reservoir.
A geomechanical study has been conducted to assess the risk of formation fracturing and sanding during a water injection test. Existing well data and supplementary core testing data from the nearby Petrel Field have been used to develop a comprehensive 1D geomechanical model for the storage reservoir and cap rock formations in the area under assessment for CCS feasibility. Considering the temperature difference between the storage formation and the injection fluid, the cooling effects could lead to a reduction of almost 15% in fracture initiation pressure (FIP). Notably, the FIP for perforations aligned parallel to the azimuth of the maximum horizontal stress is lower than for those aligned parallel to the azimuth of the minimum horizontal stress. This configuration signifies that while injection pressures surpassing FIP might trigger tensile fracturing in specific perforations, fracture propagation from the wellbore remains unlikely if the injection pressure remains below the minimum horizontal stress.
The pressure requirements for current envisaged matrix injection rates fall below the estimated FIPs. Consequently, the risk of formation fracturing during the injection test is deemed low. The propensity of sanding during flowback, considering a range of rock weakening and thermal effects of water injection, is also found to be low.
Integrated Approach for Understanding Overpressure Mechanism and Dynamic Pore Pressure Calibration Using Managed Pressure Drilling (MPD)
Authors: Chatterjee A. , Ghosh A. 
Published: October 2024

Abstract
As more exploration prospects move to deeper, high temperature high pressured reservoirs (HPHT), accurate pore pressure prediction is crucial for well planning. In such challenging environment, understanding pore pressure generating mechanism and pore pressure prediction plays a key part, particularly when no analogues are available for calibration purposes. This paper presents methodology and best practices to attune the existing pore pressure prediction methods using dynamic pore pressure data derived from Managed Pressure Drilling (MPD).
Presented methodologies includes maintaining desired bottom hole pressure (BHP) by surface Back Pressures (SBP). This was achieved by conducting dynamic flow checks and adjusting the dynamic mud weights (MWs) based on the response of flow behavior in trip tank. The bounds of the pore pressure are further tuned based on the response from gas behavior and drilling Equivalent circulating density (ECD)- Equivalent static density (ESD) contrasts. The dynamic formation integrity tests were also conducted successfully to estimate the upper limit of the drilling operating window. The petrophysical logs and pressure data from MPD were used in understanding the overpressure generation.
The conventional pore pressure estimation methods helped in identifying the depth of overpressure depth but failed to constrain the magnitude and rate of increase of pore pressure which was close to ~17.2 ppg. Hence to re-calibrate the model, pore pressure in shales were inferred from dynamic pressure tests using MPD. This was done by regular flow checks followed by monitoring the gain/return in flow and gas trends. Accordingly, the required back pressure (~a maximum of 600-700 psi) was applied in steps from the surface to balance the well plus keeping the safety margin. The pore pressure ramped up below the hydrostatic pressure depth to more than 17 ppg within 200-300 m of depth interval. The dynamic FIT was also performed with MPD in steps with increasing back pressures to define the maximum allowable mud weights and ECD. This enables dynamic adjustments to the drilling settings in response to dynamic pore pressure measurements and dynamic formation integrity data. The pore pressure derived from MPD was used in velocity-effective stress cross plot to understand the overpressure mechanism. The analysis verified the depth of unloading surface in the overpressured zone which is consistent with 120°C temperature threshold.
Proper application of these methodologies and procedures helped in HPHT well drilling plan with minimal offset geological and petrophysics information. MPD allows reasonable accuracy of the pore pressure prediction without compromising well integrity and operational safety.