bluuebunny/crossref_metadata_2025_split huggingface dataset:
Pilot-Scale Experimental Study of Gas Migration in Wellbores
Authors: Rao Sai Sashankh , Samdani Ganesh Arunkumar , Penny Glenn , Wu Qian , Wileman Angel B. , Beck Griffin C. , Bhagwat Swanand M. , Gupta V. Paul 
Published: September 2022

Abstract
Gas migration velocity impacts the planning of pressurized mud cap drilling (PMCD) as it plays a pivotal role in the selection of fluid volumes and logistics. A pilot-scale experimental investigation of gas migration under downhole conditions (up to 3,600 psi, 240°F) in water, oils, and low-density drilling fluids is presented. While bubble-rise phenomena have been studied at near atmospheric pressures, the experimental setup and measurement method for high-temperature, high-pressure gas migration is rare. Experiments were performed using three test apparatuses: two separate pressurized lengths of 3-inch pipe, one 10-ft long and the other 18-ft long, as well as a unique high-pressure, high-temperature rotating test section (RTS). The RTS is 10-ft long, having a 6 inch × 4 inch eccentric annular geometry with the inner pipe capable of rotation. The inclination of all test sections can be varied. Gas was injected from the bottom through either a 1/8-inch diameter pressurized-injection port or a liquid-gas swap mechanism i.e. zero-velocity injection. Gas migration was recorded using a camera system or gamma-ray densitometers (GRDs). Some of the key results and insights from the testing are: (1) the gas migration rate and bubble length decrease with an increase in pressure, (2) the gas migration rate is higher in inclined vs. vertical sections, (3) bubble breakup occurs as pressure increases and interfacial tension decreases, (4) the inclination of the fluid column delays bubble breakup, and (5) high viscosity hinders bubble breakup. A key observation from the testing was that Taylor bubbles that may form during the initial phase of gas entering the annulus are likely to break up under downhole conditions of high pressure, low interfacial tension, and typical field mud viscosities, resulting in much lower gas migration rates during PMCD than the commonly used industry correlations. Another observation was that the practical length limitation of the test articles prevents us from observing the full evolution of gas bubble breakup. The results seen here are in line with our previous simulation work (Samdani et al., 2021, 2022).
Novel Mixed Wettability Coating: Application in Microfluidics Fabrication
Authors: AlOmier Abdullah , Sugar Antonia , Cha Dongkyu , Ayirala Subhash , Alotaibi Mohammed , Yousef Ali , Hoteit Hussein 
Published: September 2022

Abstract
Microfluidics is an emerging technology that has gained attention by the industry for its capabilities to investigate and visualize fundamental recovery mechanisms at the pore scale in a microdevice, mimicking, to some extent, the actual rock pore-network. While current technologies are capable of building micromodels that are either water-wet or oil-wet, a technique to achieve a representative mixed-wet property is still unreached. In this work, we introduce a novel surface coating capability using thin film deposition to fabricate surfaces with selective wettability, oil-wet and water-wet, an effort to mimic actual mixed-wet rock. This unique approach enables the generation of hydrophobic surfaces in selected regions by altering the hydrophilic surface property of silicon substrate at the microscale. A selective wettability control mask and Perfluorodecyltrichlorosilane (FDTS) hydrophobic coating using molecular vapor deposition (MVD) were used for surface wetting properties alteration. Surface measurements, including contact angle measurements, X-ray photoelectron spectroscopy (XPS), and Transmission Electron Spectroscopy (TEM) imagining, were performed to evaluate the thin-film composition and morphology. By altering the wetting state of the substrate by the coated film, a selective mixed wettability surface was achieved. This technique has the potential to be utilized in microfluidic device developments. Tuning the wetting state of the substrate to mimic the mixed-wet characteristics of reservoir rocks, such as carbonates and shales, can enhance our understanding of complex fluid behaviors in porous media and provide a crucial contribution to many subsurface petroleum engineering applications such as enhanced oil recovery (EOR) and CO2 storage.
Impact of Microannulus on the Heat Exchange at the Bottomhole
Authors: Santos Livio , Dahi Taleghani Arash 
Published: September 2022

Abstract
Every injection and production operation are accompanied by heat transfer between the wellbore fluids and the formation. Often these fluids are only circulated inside the wellbore. However, the presence of microannulus, besides compromising wellbore integrity, could have a negative impact on the rate of heat transfer to and from the formation. Thermal conductivity could be critical in CO2 sequestration, thermal EOR and specially closed-loop geothermal wells. This study aims to evaluate the impact of microannulus on the heat exchange rate at the bottomhole by combining numerical results and field measurements. We propose to identify presence of microannulus by analyzing distributed temperature sensing (DTS) measurements acquired at different times from EOR and closed-loop geothermal wells. In a DTS system, temperatures are recorded continuously along an optical sensor cable placed in the wellbore. The analysis is combined with numerical simulations considering different operational conditions to estimate the severity of the microannulus. In extreme cases, the presence of microannulus was found to decrease the bottomhole temperature in 2.5%. The results also highlight the importance of proper cementing design to ensure wellbore integrity and avoid heat loss.
Lithology Identification Through X-Ray Fluorescence (XRF) Analyses on Drill Cuttings While Drilling, in Santos Basin
Authors: Vidal C. S. R. Soares de Oliveira Filipe , Tepedino Martins Gomes Ricardo , Dias Roriz Carlos Eduardo , Milani Simões Silva Krishna , Correa de Toledo Rafael 
Published: September 2022

Abstract
The present research propouses a methodology using XRF analysis on drill cuttings samples, obtained during well drilling, for characterizing pre-salt reservoir formations in the Santos Basin, southeast of Brazil in order to identify composition variations in carbonates, clay zones and potential igneous rocks.
In this study 16 off-set wells were analyzed where XRF analysis was performed on drill cuttings samples. Aftwerwards the results were compared with lithogeochemical and gamma-ray spectral logs, determining the consistency of the data. The lithological interpretations were based on macroscopic (sidewall core samples - SWC) and microscopic (thin section) descriptions and geochemical analyses from SWC samples. This permitted us to comprehend the variations observed in the carbonate reservoir and to identify possible igneous rocks.
From the results, a pattern of responses could be established for the XRF method for each lithology within the Pre-salt section, using the major elements (Mg, Ca, Si, k, Fe and Al) and some minor elements and trace elements (Sr, Rb, Y, Zr, Ti, Nb, Ga). The variations of the major elements were best observed in radar and bar charts, that use only the major elements, which enabled the separation of the lithological section into six main sets: limestones, dolomitic carbonates, silicified carbonates, carbonates with magnesian clay, siliciclastic rocks (shale/siltstone/sandstone) and basic igneous rocks (basalt/diabase). For quality control, still during drilling, comparative analysis by three approaches was proposed: a) the systematic comparison of the proportion of elements composing the same mineral, such as Ca and Sr, K and Rb, and Al and Ga; b) the comparison of XRF data with XRD data; and c) comparison with calcimetry data in a cutting sample. Furthermore, in order to support the interpretations, four crossplots (Ca × Si; K.Rb × Al.Zr; Rb × Sr; Zr × Fe) and one crossover (Rb × Sr) were generated aiming to individualize the six lithological types described, as well as diagrams from the literature to identify the igneous rock type.
The use of XRF on cuttings to determine lithologies during the drilling of petroleum wells is new in the literature, as well as the proposed quality control, being useful for the characterization of complex reservoirs such as Santos Basin pre-salt, being a methodology already used since 2018 by Petrobras.
Experimental and Modeling Study of CO2 EOR and CO2 Storage in Heavy Oil Reservoirs
Authors: Wang Wuchao , Liu Huiqing , Dong Xiaohu , Chen Zhangxin , Yang Farong , Li Yu , Guo Yunfei , Wang Zhipeng , Tian Yunfei , Lu Ning , Xu Wenjing , Jiang Xiuchao 
Published: September 2022

Abstract
This study focuses on unveiling the interaction between injected CO2 and heavy oil through adequate phase behavior analyses. Moreover, the potential of CO2 EOR and CO2 storage were evaluated through injection scheme optimization and sensitivity analysis.
Experimentally, the PVT experiments including CO2/heavy oil systems have been carried out to measure oil swelling, solubility, viscosity reduction, and density variation. The MMP of the heavy oil-CO2 mixture has been determined to provide the reference pressure for core displacements. CO2 injection experiments were conducted to examine the performance of CO2 enhanced recovery under different pressure. Different injection schemes were experimentally simulated including water flood, injection water followed by CO2 flooding, and injection water followed by CO2-WAG (water alternating CO2 flooding). Based on these studies, the sensitivity analysis was run on the validated model to examine the effects of different parameters including gas injection rate, CO2 slug size, and CO2-WAG cycle number on the heavy oil recovery and CO2 storage efficiency.
As the saturation pressure of the heavy oil-CO2 mixture increases, the solubility of CO2 in heavy oil, the swelling, and the viscosity reduction increase at reservoir temperature (60°C). Although CO2 displacement efficiency and CO2 storage efficiency increase with increasing injection pressure, the increase in these two factors become significantly slower as pressure exceeds the MMP (30 MPa). Injection water followed by CO2-WAG increased oil recovery more than water flood or injection water followed by CO2 flooding. Only considering the influence of single factor conditions, the higher the injection CO2 rate, CO2 slug size, or WAG cycles number, the higher the cumulative oil production. However, based on comprehensive consideration of oil displacement rate, CO2 storage efficiency, CO2 cumulative storage, and cumulative WOR (water-oil ratio), reasonable injection CO2 rate, CO2 slug size, and WAG cycles number were finally optimized and screened out as 30,000 m3/day, 0.5 PV, and 5, respectively.
The outcomes of this work provide valuable information for designing a suitable CO2 flooding strategy in heavy oil reservoir engineering applications. It also could bring significant economic and environmental benefits by improving oil recovery and reducing CO2 emissions.
Middle East Giant Carbonate Field: Integrated Water Injection Optimization Workflow
Authors: Del Fraro Stefano , Renna Simona , Tfaili Hana , Mariotti Pamela , Tarantini Vincenzo , Tanganelli Francesco , Salvi Valeria 
Published: September 2022

Abstract
A proper reservoir management is mandatory to optimize the water injection strategy through time, since the injected fluids tend to flush the same preferential paths, leading to a significant reduction of the incremental swept oil.
This paper shows the results of an integrated workflow applied to a giant brown field with complex geology. The proposed workflow is based on a semi-automated process to optimize water injection, embodying the improvement and assessment of the 3D model.
An integrated Production Data Analysis (iPDA), initially available, allowed to understand the main fluid dynamics of the reservoir, which were integrated in the 3D model since the earliest setup. Streamlines methodology was then used to compare the 3D model with the iPDA outputs in terms of subsurface dynamics, guiding the reservoir model history match process. Finally, streamlines traced on the validated model allowed to optimize water injection strategy for the forecast simulations using a semi-automatic process. It relies upon an iterative loop of rates redistribution among all active injectors, based on their own oil displacement efficiency calculated using dedicated software.
The mentioned workflow was applied on Beta formation of Alpha field, which is a mid-Cenomanian carbonate giant oilfield in the Middle East region with more than sixty years of production and about five hundred drilled wells, characterized by karstic behavior. In this very challenging context, streamlines simulation technique, mostly used during the HM phase, resulted in an increase of 3D model reliability and representativeness of the main evidence from iPDA. This led to generate more robust forecast scenarios.
In particular, the proposed workflow allowed to optimize the water injection strategy, adequately redistributing the overall available injection rate between all the injectors, promoting the most efficient ones, and reducing the inefficient. This approach resulted in a definitively appreciable oil reserves potential gain, consisting in the plateau extension of about one year from the forecast 3D simulations.
The economic value of this result can be better appreciated if we consider that it is associated only to the re-distribution of the injection rate, without any additional capex.
Limiting Deteriorative Impacts of Oil-Based Mud Residuals on Cement Bonding
Authors: Tabatabaei Maryam , Santos Livio , Al Hassan Ali Ahmed , Dahi Taleghani Arash 
Published: September 2022

Abstract
Successful cementing relies on an effective removal of oil-based muds (OBMs) specially from rock and casing surfaces. However, most OBMs are heavily absorbed onto the mineral surfaces as well as casing, deteriorating the interfacial bonding of cement to these surfaces. We present a novel cement additive made from treated surface-modified graphite nanoplatelets (GNPs) to minimize the impact of mud residuals on the bonding strengths of cement. Experimental results show that after spacer flushing for the cases of limestone and sandstone cores, treated GNPs not only limit the impact of mud residuals at the interfaces, but also, raise the bonding strength beyond that corresponding to water saturated cores.
Geological Characterization of Lower Devonian Reservoirs in Reggane Basin, Algeria
Authors: Djezzar Sofiane , Boualam Aldjia , Ouadi Habib , Laalam Aimen , Mouedden Nadia , Merzoug Ahmed , Chemmakh Abderraouf 
Published: September 2022

Abstract
In the Reggane basin, the most promising petroleum system is represented by the Lower Devonian, Cambro-Ordovician, and Carboniferous reservoirs. Most of the traps are linked to structures with very complex geometry, generally leaning on reverse faults, under superficial detachment levels. The generation of hydrocarbons took place, in the Paleozoic during the burial period (Upper Devonian-Carboniferous) and probably during the overheating of the Jurassic. The basin architecture is the outcome of a superposition of several tectonic phases from the Caledonian to the Hercynian tectonic events. The main reservoirs are in the North-East part of the basin, namely the Lower Devonian, Ordovician, and Carboniferous. The Gedinnian and the Siegenian are the main reservoirs of the Lower Devonian sequence, with the Emsian as a secondary reservoir. The Carboniferous and Ordovician reservoirs became targets after the discovery of dry gas in the Kahlouche and Anzeglouf areas. The main gas fields in the Reggane basin are Hassi-M’dakane, Feidjet-El-Had, Kahal-Tabalbala, Djebel-Hirane, Kahlouche, Tiouliline, Reggane, Azrafil, and Anzeglouf. The current geometry of the Reggane basin is marked by two major structural axes, resulting from a complex tectonic history. Reggane basin is elongated NW – SE, relatively asymmetric. The southern flank of the basin is characterized by a hallow dip plunging towards the North and affected by rare reverse faults. On the other hand, the northern flank is affected by many faults and folds. These faults arrangement of the various faults that have affected this basin can be broken down into two main sets: NW - SE set: this direction is very important; it all appears along the northern edge of the basin and presents a comparable direction to the Ougarta ridge. A set of submeridian directions: concentrated in the SE part of the basin (eastern periclinal closure constituting the transition zone between the Reggane basin and the Azzel Matti slab). This fault sets form an extension of the major submeridian accidents in the Hoggar shield. Two other directions of less represented the E-W faults forming an accident relay along the edge of the basin with the Ougarta ridge and the NE - SW faults. This study will help to define the quality and extension of the Lower Devonian sandstone reservoirs in the northern part of the Reggane basin, the construction of favorable zone maps for exploration with risk-weighted reservoir spaces, identification, and evaluation of "Tight Gas Reservoir", and trap analysis and petroleum potential the Reggane basin.
Diffusional and Electrical Tortuosity in Unconventional Shale Reservoirs
Authors: Odiachi Judah , Cruz Felipe , Tinni Ali 
Published: September 2022

Abstract
Tortuosity is a porous medium property which measures the interconnectedness and sinuosity of the pore space. It is important in order to understand advective, diffusive transport and electric current flow in low porosity low permeability reservoirs such as unconventional shale reservoirs. However, experimental values of diffusional and electrical tortuosity of shales are scarce in the literature. To improve the understanding of diffusive transport and electrical flow in unconventional shale reservoirs, we have conducted the independent measurements of diffusional and electrical tortuosities of 12 shale samples from Utica, Bakken, Wolfcamp and Eagle Ford formations and 3 sandstones as control samples.
For the purpose of this study, the samples were characterized by measurements of total organic carbon (TOC), mineralogy, and total porosity. Diffusional tortuosity was measured by immersing brine saturated samples into D2O to allow the diffusion of D2O into the samples. The rates at which D2O diffused into the samples were measured with 12 MHz NMR measurements. The combination of the effective diffusion coefficient of D2O and the bulk diffusion coefficient of D2O were used to compute the diffusional tortuosity.
To measure electrical tortuosity, the samples were resaturated with 2.5% KCl brine prior to immersion into 6% KCl brine. The measurements of the samples’ resistivities as function of time after the immersion into the 6% KCl brine were used to compute ionic diffusion coefficients. Electrical tortuosity was calculated using the bulk ionic diffusion coefficient and the ionic diffusion coefficients of the samples.
The results show that diffusional and electrical tortuosity have similar values. These tortuosities vary between 1.7 and 5.8 for shale samples while they have values between 1.4 and 3.9 for sandstones. We also observed that TOC exerts a primary control on the tortuosity of shales.
Optimizing Drill Bit Design Iteration with a New Sensor System Developed for Large-Scale Deployment and Automated Analysis of Drilling Dysfunctions
Authors: Schen Aaron , Graham Ryan , Engel Braden 
Published: September 2022

Abstract
A drill bit dynamics sensor system has been developed with a new approach that enables economical, widespread use of downhole data to improve bit design. The system emphasizes ease of deployment and minimal manpower requirements for data interpretation. The goal was to develop a system appropriate for deployment on a new scale to the bit industry. The system consists of a small in-bit sensor coupled with an automated software system that provides direct design guidance targeted at drill bit specialists. This paper aims to detail the design considerations used to develop this system and provide an example application of the technology from field testing.
Unconventional Najmah Reservoir Formation Evaluation in West Kuwait Using an Innovative-Integrated Approach for Productivity and Potential
Authors: Fawzy Mahmoud , Al-Morakhi Rasha , Quttainah Riyad , Kalawina Mahmoud , Balliet Ron , Swidan Zakaria 
Published: September 2022

Abstract
Abduliyah field is one of the major fields in the West Kuwait asset where the Najmah shale (Kerogen unit) is present. The Najmah shale is a high Kerogen content, calcareous mudstone and is considered the main source rock for shallower depth oil reservoirs in Kuwait, due to the shortage of data especially core data at reservoir condition there is enormous uncertainty in the determination of the unconditional reservoir properties that need to be evaluated to confirm both economic and operational success. An integrated logging approach was implemented using pressurized sidewall rotary coring, magnetic resonance, borehole image logs, conventional logs, and core analysis to assess the Najmah storage volume, and quantify the potential hydrocarbon fluids in place and provide a time and cost-efficient method of reservoir evaluation.
2D Surface Roughness Quantification for Enhanced Petrophysical Applications
Authors: Singer Gabriela , Ma Shouxiang Mark , Chen Songhua , Eid Mahmoud 
Published: September 2022

Abstract
Surface roughness is an essential rock parameter affecting petrophysical properties that are surface sensitive such as characterization of pore structure and wettability. For instance, Wenzel's contact angle formula for rough surfaces requires knowledge of the surface roughness, and surface roughness is expected to speed up aging of cores in crude oil for wettability restoration. In addition, proper quantification of surface roughness is critical for obtaining representative, roughness-independent, pore sizes for applications such as prediction of permeability and interpretation of capillary pressure curves.
Intuitively, a surface is better characterized in 2D than in 1D. This 2D study is a continuation and enhancement of the previous 1D work, recently published in the SPE Journal (Ma et al., 2021). In this current paper, a comprehensive investigation of 1D versus 2D surface roughness measurements is conducted to evaluate and cross validate the two approaches. In this study, surface roughness is measured on 26 carbonate rock samples by laser scanning confocal microscopy (LSCM), where both the 1D absolute increment surface roughness, Sr, as well as 2D interfacial area ratio of surface roughness, Sdr, are reported. As expected, results indicate that surface roughness characterized by 2D Sdr has a greater dynamic range than the 1D Sr measurement, i.e., the 2D Sdr provides a more representative characterization of surface roughness.
A detailed account of methodologies, assumptions, limitations, validation and applications of the 1D and 2D surface roughness characterization is documented in this paper. To extract the roughness features present on rock grain surfaces, effects of de-spiking and filter length, used to eliminate pore size effects, are investigated. For specific applications of surface roughness corrected pore size estimation from nuclear magnetic resonance (NMR) measurements, differences in length-scales of surface roughness are compared between LSCM measurement and that derived from NMR diffusion-T2 plus BET surface area. The surface roughness-corrected NMR pore-size distribution is also validated against the pore-size distribution obtained from measurement of micro-CT scanning.