Texas

Abstract Finite element simulations investigate the effect of cement sheath length and proximity to perforations, varying the spacing of these and their length. The motivation is to assess the well integrity risk in fracturing operations, typical in shale gas or tight sandstone stimulation operations. Other applications are de-risking of injection operations in CO2 or H2 storage. Simplified simulations highlight unwanted associated fracturing in hydraulic fracturing operations, or as additional consequences of unplanned fracturing occurring due to injectivity impairment. Several cases are simulated: 1. Cased, cemented and perforated horizontal well interval; 2. Open hole perforated horizontal well interval; 3. Vertical cased and cemented interval. Results show that under some circumstances, fracturing may be expected in the well's cement sheath. These are locations where simulations show a possible fracturing scenario which could lead to unwanted pressure communication. However, the simulations all agree that there is no induced fracturing at more distant cement sheath sections. The major risk shown here is fracture initiation close to the perforated interval, suggesting that propagation along the cement sheath, although possible, is less likely.

OnePetro

doi: 10.2118/214448-MS

SPE

SPE-214448-MS

SPE EuropEC - Europe Energy Conference featured at the 84th EAGE Annual Conference & Exhibition

Country:

North America > United States (1.00)
Europe (1.00)

Genre:

Research Report > New Finding (0.34)
Research Report > Experimental Study (0.34)

Industry:

Energy > Oil & Gas > Upstream (1.00)
Government > Regional Government > North America Government > United States Government (0.46)

Oilfield Places:

North America > United States > West Virginia > Appalachian Basin > Marcellus Shale Formation (0.99)
North America > United States > Virginia > Appalachian Basin > Marcellus Shale Formation (0.99)
North America > United States > Texas > Permian Basin > Yeso Formation (0.99)
(29 more...)

SPE Disciplines:

Well Drilling > Drilling Operations > Directional drilling (1.00)
Well Drilling > Casing and Cementing (1.00)
Well Completion > Hydraulic Fracturing (1.00)
Well Completion > Completion Installation and Operations > Perforating (1.00)

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Transient Pressure Interference During CO2 Injection in Saline Aquifers

Zeidouni, Mehdi (Louisiana State University)

OnePetroJune, 2023

Abstract CO2 injection in subsurface geological formations (e.g. deep saline aquifers) causes pressure perturbations over a large area surrounding the injection well. Observation wells are widely considered in geologic CO2 storage (GCS) projects where the pressure perturbation induced by CO2 injection is measured. In this work, we use analytical and numerical modeling tools along with field data to examine the pressure behavior in GCS projects before and after CO2 arrival at an observation well. Prior to CO2 arrival, a baseline pressure trend is established which corresponds to single-phase brine flow across the observation well (approximated by Theis solution). Therefore, analysis of early-time pressure data is straightforward, provides the single-phase flow characteristics (mobility and storativity), and helps establishing a baseline pressure change that can be extended beyond the single-phase flow period at the observation well. Upon CO2 arrival, a departure from this baseline trend is expected. For the pressure to detect the CO2 arrival at an observation well, the departure from baseline pressure behavior must be significant and well above the background noise levels. We use existing analytical models to determine the strength of the expected pressure departure signal from the baseline trend upon CO2 arrival. The strength of the expected pressure departure is found to be directly proportional to the mobility ratio. Accordingly, we establish a criterion to determine whether the pressure at an observation well can detect the CO2 arrival. We present an analysis approach through application to synthetic and field data and show the characteristic pressure behavior before and after CO2 arrival. We show that while generally the pressure can be either above or below the expected baseline pressure trend, it would be likely above the baseline upon CO2 arrival. This is because the mobility ratio becomes less than unity after CO2 arrival. We show that depending on the reservoir characteristics, changes in the pressure trend may or may not be sufficient to detect the CO2 arrival.

OnePetro

doi: 10.2118/215939-MS

SPE

SPE-215939-MS

SPE EuropEC - Europe Energy Conference featured at the 84th EAGE Annual Conference & Exhibition

Country:

Europe (0.68)
North America > United States > Texas (0.47)

Industry: Energy > Oil & Gas > Upstream (1.00)

Oilfield Places: North America > United States > Texas > West Gulf Coast Tertiary Basin > South Liberty Field (0.99)

SPE Disciplines:

Reservoir Description and Dynamics > Storage Reservoir Engineering > CO2 capture and sequestration (1.00)
Reservoir Description and Dynamics > Improved and Enhanced Recovery > Chemical flooding methods (1.00)
Reservoir Description and Dynamics > Formation Evaluation & Management > Drillstem/well testing (1.00)
Production and Well Operations > Well & Reservoir Surveillance and Monitoring (1.00)

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Paradigm Shift in Conventional Hydraulic Fracturing - Emerging Fracturing Techniques Using Thermochemical Fluids

Al-Ghamdi, Ahmed (Saudi Aramco) | Al-Jawad, Murtada (King Fahd University of Petroleum and Minerals) | Mahmoud, Mohamed (King Fahd University of Petroleum and Minerals)

OnePetroJune, 2023

Abstract Hydraulic fracturing has long been an established well stimulation technique in the oil & gas industry, unlocking hydrocarbon reserves in tight and unconventional reservoirs. The two types of hydraulic fracturing are proppant fracturing and acid fracturing. Recently, a new of hydraulic fracturing is emerging which is delivering yet more enhanced production/injection results. This paper conducts a critical review of the emerging fracturing techniques using Thermochemical fluids. The main purpose of hydraulic fracturing is to break up the reservoir and create fractures enhancing the fluid flow from the reservoir matrix to the wellbore. This is historically achieved through either proppant fracturing or acid fracturing. In proppant fracturing, the reservoir is fractured through a mixture of water, chemicals and proppant (e.g. sand). The high-pressure water mixture breaks the reservoir, and the proppant particles enter in the fractures to keep it open and allow hydrocarbon flow to the wellbore. As for acid fracturing, the fractures are kept open through etching of the fracture face by acid such as Hydrochloric Acid (HCl). An emerging technique of hydraulic fracturing is through utilization of thermochemical solutions. These environmentally friendly and cost-efficient are not reactive as surface conditions, and only react in the reservoir at designated conditions through reservoir temperature or pH-controlled activation techniques. Upon reaction, the thermochemical solutions undergo an exothermic reaction generating in-situ foam/gases resulting in creating up to 20,000 psi in-situ pressure and temperature of up to 700 degrees Fahrenheit. Other reported advantages from thermochemical fracturing include the condensate bank removal (due to the exothermic reaction temperature) and capillary pressure reduction.

OnePetro

doi: 10.2118/214376-MS

SPE

SPE-214376-MS

SPE EuropEC - Europe Energy Conference featured at the 84th EAGE Annual Conference & Exhibition

acid, al-majed, al-nakhli, ammonium chloride, application, asphaltene inhibition, asphaltene remediation, complex reservoir, condensate reservoir, core analysis, drilling fluid chemistry, drilling fluid formulation, drilling fluid property, drilling fluid selection and formulation, drilling fluids and materials, Engineering, europe government, experiment, flow assurance, fluid loss control, fracture, fracturing fluid, fracturing materials, Hassan, hydrate inhibition, Hydrate Remediation, hydraulic fracturing, injection, Journal, Mahmoud, microfracture, oilfield chemistry, paraffin remediation, patent, permeability, Petroleum Science, Production Chemistry, proppant, reaction, remediation of hydrates, Reservoir Characterization, reservoir geomechanics, scale inhibition, scale remediation, seismic surveying, stimulation, survey article, thermochemical fluid, united states government, Upstream Oil & Gas, wax inhibition, wax remediation

Country:

Europe (0.93)
North America > United States > Texas (0.47)

Genre:

Research Report (0.47)
Overview (0.46)

Geophysics: Geophysics > Seismic Surveying (0.68)

Industry: Energy > Oil & Gas > Upstream (1.00)

Oilfield Places:

North America > United States > Texas > West Gulf Coast Tertiary Basin > Eagle Ford Shale Formation (0.99)
North America > United States > Texas > Sabinas - Rio Grande Basin > Eagle Ford Shale Formation (0.99)
North America > United States > Texas > Maverick Basin > Eagle Ford Shale Formation (0.99)

SPE Disciplines:

Well Completion > Hydraulic Fracturing > Fracturing materials (fluids, proppant) (1.00)
Reservoir Description and Dynamics > Reservoir Characterization > Reservoir geomechanics (1.00)
Production and Well Operations > Production Chemistry, Metallurgy and Biology > Inhibition and remediation of hydrates, scale, paraffin / wax and asphaltene (1.00)
(4 more...)

Technology: Information Technology (0.68)

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Visualization of Surfactant Flooding in Tight Reservoir Using Microfluidics

Scerbacova, Alexandra (Skolkovo Institute of Science and Technology, LABADVANCE) | Pereponov, Dmitrii (Skolkovo Institute of Science and Technology, LABADVANCE) | Tarkhov, Michael (Institute of Nanotechnology of Microelectronics of the Russian Academy of Sciences) | Kazaku, Vitaly (Skolkovo Institute of Science and Technology) | Rykov, Alexander (Institute of Nanotechnology of Microelectronics of the Russian Academy of Sciences) | Filippov, Ivan (Institute of Nanotechnology of Microelectronics of the Russian Academy of Sciences) | Zenova, Elena (Institute of Nanotechnology of Microelectronics of the Russian Academy of Sciences) | Krutko, Vladislav (Gazpromneft STC LLC) | Cheremisin, Alexey (Skolkovo Institute of Science and Technology, LABADVANCE) | Shilov, Evgeny (Skolkovo Institute of Science and Technology, LABADVANCE)

OnePetroJune, 2023

Abstract Surfactant flooding is among the most studied and widespread EOR technologies that is being introduced into tight and low-permeable reservoirs to mobilize trapped oil. Typically, the selection of formulations for chemical flooding is associated with numerous challenges and constraints such as time-consuming core flooding tests, the high cost of the tests with modern saturation control methods, and a limited amount of core samples. To overcome these issues, microfluidic technology was applied to optimize the screening of surfactant compositions for flooding. The workflow of this project consisted of five main steps: (1) fabrication of microfluidic chips, (2) surfactant screening in bulk, (3) surfactant flooding in microfluidic chips, (4) image analysis and data interpretation. Silicon-glass microfluidic chips, which are 2D representatives of the reservoir porous media, were used in the experiments. The porous structure geometry was developed based on CT images of core samples from a particular field with low permeability. For the selected surfactants, interfacial behavior on the boundary with n-decane was studied and correlated with hydrocarbon recovery ability. The results obtained revealed that the IFT patterns have a significant influence on displacement efficiency. Thus, the surfactant compositions with a lower initial IFT than the equilibrium value achieved higher recovery factors.

OnePetro

doi: 10.2118/214419-MS

SPE

SPE-214419-MS

SPE EuropEC - Europe Energy Conference featured at the 84th EAGE Annual Conference & Exhibition

Country:

North America > United States (0.47)
Europe > Austria (0.28)

Industry:

Materials > Chemicals (1.00)
Energy > Oil & Gas > Upstream (1.00)

Oilfield Places:

North America > United States > Texas > West Gulf Coast Tertiary Basin > Eagle Ford Shale Formation (0.99)
North America > United States > Texas > Sabinas - Rio Grande Basin > Eagle Ford Shale Formation (0.99)
North America > United States > Texas > Maverick Basin > Eagle Ford Shale Formation (0.99)

SPE Disciplines:

Reservoir Description and Dynamics > Improved and Enhanced Recovery > Waterflooding (1.00)
Reservoir Description and Dynamics > Improved and Enhanced Recovery > Chemical flooding methods (1.00)

Technology:

Information Technology > Artificial Intelligence (0.48)
Information Technology > Sensing and Signal Processing > Image Processing (0.34)

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Numerical Investigation of the Primary Mechanisms Leading to Complex Fracture Morphology in the Near-Wellbore Region

Kryvenko, Serhii (Texas A&M University) | Moridis, George Julius (Texas A&M University) | Blasingame, Thomas Alvin (Texas A&M University)

OnePetroJune, 2023

Abstract This paper presents the results of numerical simulations of hydraulic fracturing in the immediate vicinity of the wellbore. This research aims to identify the primary mechanisms underlying the complexities in both the fracture morphology and propagation of longitudinal fractures. The study shows that the perforation attributes and characteristics, the cement quality, and the reservoir heterogeneity have a significant impact on the resulting morphology and the trajectory of the propagating hydraulic fracture. The study is based on properties and conditions associated with a field study conducted in the Austin Chalk formation, and concludes that the pattern and the dimensions of the perforations are essential factors controlling the fracture initiation pressure and morphology. The results of the simulation studies provide insights into the principles and mechanisms controlling fracture branching and the initiation of longitudinal fractures in the near-wellbore region and can lead to improved operational designs for more effective fracturing treatments.

OnePetro

doi: 10.2118/214403-MS

SPE

SPE-214403-MS

SPE EuropEC - Europe Energy Conference featured at the 84th EAGE Annual Conference & Exhibition

Country: North America > United States > Texas (1.00)

Genre:

Research Report > New Finding (1.00)
Research Report > Experimental Study (1.00)

Geologic Time: Phanerozoic (0.46)

Industry: Energy > Oil & Gas > Upstream (1.00)

Oilfield Places:

North America > United States > Texas > West Gulf Coast Tertiary Basin > Eagle Ford Shale Formation (0.99)
North America > United States > Texas > Sabinas - Rio Grande Basin > Eagle Ford Shale Formation (0.99)
North America > United States > Texas > Maverick Basin > Eagle Ford Shale Formation (0.99)
(3 more...)

SPE Disciplines:

Well Drilling > Wellbore Design > Wellbore integrity (1.00)
Well Completion > Hydraulic Fracturing (1.00)
Well Completion > Completion Installation and Operations > Perforating (1.00)
(3 more...)

Technology:

Information Technology > Communications > Networks (0.46)
Information Technology > Modeling & Simulation (0.35)

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Feasibility Evaluation of Warm Solvent Assisted Gravity Drainage Process in Low-Carbon Developing Super-Heavy Oil or Oil Sands Project

Liang, Guangyue (Research Institute of Petroleum Exploration and Development, CNPC) | Xie, Qian (Research Institute of Petroleum Exploration and Development, CNPC) | Liu, Yang (Research Institute of Petroleum Exploration and Development, CNPC) | Liu, Shangqi (Research Institute of Petroleum Exploration and Development, CNPC) | Xia, Zhaohui (Research Institute of Petroleum Exploration and Development, CNPC) | Bao, Yu (Research Institute of Petroleum Exploration and Development, CNPC) | Zhou, Jiuning (Research Institute of Petroleum Exploration and Development, CNPC)

OnePetroJune, 2023

Abstract It is very difficult to realize good economy returns using conventional SAGD process in many oil sands projects due to large CPF investment, massive steam injection, expensive surface diluent adding and increasing carbon emission tax. By contrast, warm solvent assisted gravity drainage process (WSAGD) is a promising low-carbon technology to deal with these SAGD challenges. This paper conducted feasibility evaluation by combined with Nsolv Best pilot analysis and a series of physical simulations. From 2014 to 2017, WSAGD pilot was successfully carried out by injecting butane at 60℃ in Suncor Dover oil sands. Its reservoir geological characteristics, physical properties, development technology policy and production performance were systematically analyzed. Combined with 4D seismic interpretation, RST and observation well data, the size and growth rate of solvent chamber were monitored and analyzed. Considering great uncertainty in numerical simulations influenced by many factors including grid size, solvent diffusion coefficient, interfacial tension and capillary force, a series of experimental tests and physical simulations were conducted. The behavior of viscosity reduction, interfacial tension reduction and microscopic oil displacement related to different solvents were systematically tested including propane, butane, pentane and hexane. Particularly, the performance of SAGD and WSAGD process were evaluated by 2D and 3D visual physical simulations. In Nsolv Best pilot, the target reservoir is low pressure, thin and shallow buried. The oil rate reached 250-300 barrels per day under 300 m horizontal section, and API degree of produced oil was upgraded to 13-16 from original 8. After 3 years of tests, the width of solvent chamber is 40-60m, lateral and vertical 1.56 m and 0.96 m per month, and horizontal conformance is 67%. The experiments results show that viscosity reduction trend will flatten out when the solvent concentration exceeds 10 vol% due to partial asphaltene precipitation. Both sweep efficiency and displacement efficiency of hot water, steam, gaseous and liquid hexane are increasing with temperature increase. Compared with other medium, sweep efficiency and displacement efficiency of gaseous hexane are higher due to greater dissolving ability and speed in bitumen. Both 2D and 3D experimental results indicate that WSAGD process achieves faster vertical solvent chamber and higher recovery factor than conventional SAGD process. Besides, gaseous pentane has significant upgrading effect considering substantial reduction of asphaltene and resin in the produced oil, which is not available in conventional SAGD process. This paper first systematically compares the mechanisms and performance of warm solvent assisted gravity drainage (WSAGD) process with SAGD process by physical simulations. It presents a promising low-carbon technology to enhance oil recovery, partially upgrade the produced oil and reduce carbon dioxide emissions in developing super-heavy oil or oil sands project.

OnePetro

doi: 10.2118/214347-MS

SPE

SPE-214347-MS

SPE EuropEC - Europe Energy Conference featured at the 84th EAGE Annual Conference & Exhibition

Country:

Europe (0.93)
North America > Canada > Alberta (0.16)

Genre:

Research Report > New Finding (0.34)
Research Report > Experimental Study (0.34)

Geophysics: Geophysics > Seismic Surveying (0.54)

Industry:

Materials > Chemicals > Commodity Chemicals > Petrochemicals (1.00)
Energy > Oil & Gas > Upstream (1.00)

Oilfield Places: North America > United States > Texas > Permian Basin > Central Basin > Dover Field > Strawn Formation (0.98)

SPE Disciplines:

Reservoir Description and Dynamics > Unconventional and Complex Reservoirs > Oil sand, oil shale, bitumen (1.00)
Reservoir Description and Dynamics > Improved and Enhanced Recovery > Thermal methods (1.00)
Health, Safety, Environment & Sustainability > Sustainability/Social Responsibility > Sustainable development (1.00)
(2 more...)

Technology: Information Technology (0.88)

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Machine-Learning Based Selection of Candidate Wells for Extended Shut-In Due to Fluctuating Oil Prices

Lobut, Beyza (Istanbul Technical University) | Artun, Emre (Istanbul Technical University)

OnePetroJune, 2023

Abstract Fluctuations in oil prices adversely affect decision making situations in which performance forecasting must be combined with realistic price forecasts. In periods of significant drops in the prices, shutting in wells for extended durations such as 6 months or more may be considered for economic purposes. For example, prices during the early days of the Covid-19 pandemic forced operators to consider shutting in all or some of their active wells. In the case of partial shut-in, selection of candidate wells may evolve as a challenging decision problem considering the uncertainties involved. In this study, a mature oil field with a long (50+ years) production history with 150+ wells is considered. Reservoirs with similar conditions face many challenges related to economic sustainability such as frequent maintenance requirements and low production rates. We aimed to solve this decision-making problem through unsupervised machine learning with the help of the data obtained during production. Average reservoir characteristics at well locations, well performance statistics and well locations are used as potential features that could characterize similarities and differences among wells. After a multivariate data analysis that explored correlations between all parameters, K-means clustering algorithm was used to identify groups of wells that are similar with respect to aforementioned features. Using the field’s reservoir simulation model, scenarios of shutting in different groups of wells were simulated. 3 years of forecasted reservoir performance was used for economic evaluation that assumed an oil price drop to $30/bbl for 6, 12 or 18 months. Results of economic analysis were analyzed to identify which group of wells should have been shut-in by also considering the sensitivity to different price levels. It was observed that well performances can be easily characterized in the 3-cluster case as low, medium and high performance wells. Analyzing the forecasting scenarios showed that shutting in all or high- and medium-performance wells altogether during the downturns results in better economic outcomes. The results were most sensitive to the oil price during the high-price era. This study demonstrated the effectiveness of unsupervised machine learning in well classification, particularly for the problem studied. Operating companies may use this approach for selecting wells for extended durations of shut-in in periods of low oil prices.

OnePetro

doi: 10.2118/214353-MS

SPE

SPE-214353-MS

SPE EuropEC - Europe Energy Conference featured at the 84th EAGE Annual Conference & Exhibition

Country:

Europe (1.00)
North America > United States > Texas (0.47)

Genre: Research Report > New Finding (0.86)

Industry: Energy > Oil & Gas > Upstream (1.00)

Oilfield Places:

North America > United States > Texas > West Gulf Coast Tertiary Basin > Eagle Ford Shale Formation (0.99)
North America > United States > Texas > Sabinas - Rio Grande Basin > Eagle Ford Shale Formation (0.99)
North America > United States > Texas > Maverick Basin > Eagle Ford Shale Formation (0.99)
Europe > Germany > Bierwang Field (0.99)

SPE Disciplines:

Reservoir Description and Dynamics (1.00)
Production and Well Operations (1.00)
Management (1.00)
Data Science & Engineering Analytics > Information Management and Systems > Artificial intelligence (1.00)

Technology: Information Technology > Artificial Intelligence > Machine Learning > Statistical Learning > Clustering (0.91)

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Shale Characterization Using T1-T2* Magnetic Resonance Relaxation Correlation Measurement at Low and High Magnetic Fields

Zamiri, Mohammad Sadegh (University of New Brunswick) | Guo, Jiangfeng (University of New Brunswick) | Marica, Florea (University of New Brunswick) | Romero-Zerón, Laura (China University of Petroleum (Beijing)) | Balcom, Bruce J. (University of New Brunswick)

OnePetroJune, 2023

Abstract Shale characterization is complicated by low porosity and low permeability. Nano-porosity and a high degree of heterogeneity present further difficulties. H magnetic resonance (MR) methods have great potential to provide quantitative and spatially resolved information on fluids present in porous rocks. The shale MR response, however, is challenging to interpret due to short-lived signals that complicate quantitative signal detection and imaging. Multicomponent signals require high-resolution methods for adequate signal differentiation. MR methods must cope with low measurement sensitivity at low field. In this paper, T1-T2* and Look-Locker T1*-T2* methods were employed to resolve the shale signal for water, oil, and kerogen at high and low field. This permits fluid quantification and kerogen assessment. The T1-T2* measurement was employed to understand and control contrast in the single-point ramped imaging with T1 enhancement (SPRITE) imaging method. This permitted imaging that gave separate images of water and oil. Water absorption/desorption, evaporation, step pyrolysis, and water uptake experiments were monitored using T1-T2* measurement and MR imaging. The results showed (i) the capability of the T1-T2* measurement to differentiate and quantify kerogen, oil, and water in shales, (ii) the characterization of shale heterogeneity on the core plug scale, and (iii) demonstrated the key role of wettability in determining the spatial distribution of water in shales.

OnePetro

doi: 10.30632/PJV64N3-2023a5

SPWLA

SPWLA-2023-v64n3a5

Petrophysics

Country:

North America > United States > Texas (0.93)
North America > Canada (0.93)
Europe (0.93)

Genre: Research Report > New Finding (0.48)

Industry: Energy > Oil & Gas > Upstream (1.00)

Oilfield Places:

North America > United States > West Virginia > Appalachian Basin > Marcellus Shale Formation (0.99)
North America > United States > West Virginia > Appalachian Basin > Marcellus Field > Marcellus Shale Formation (0.99)
North America > United States > Virginia > Appalachian Basin > Marcellus Shale Formation (0.99)
(14 more...)

SPE Disciplines:

Reservoir Description and Dynamics > Unconventional and Complex Reservoirs > Shale oil (1.00)
Reservoir Description and Dynamics > Unconventional and Complex Reservoirs > Shale gas (1.00)
Reservoir Description and Dynamics > Reservoir Characterization > Exploration, development, structural geology (1.00)
Reservoir Description and Dynamics > Formation Evaluation & Management (1.00)

Technology: Information Technology > Sensing and Signal Processing > Image Processing (0.46)

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Analytical Models for Predicting the Formation Resistivity Factor and Resistivity Index at Overburden Conditions

OnePetroJune, 2023

Abstract In this study, new parameters referred to as rock resistivity modulus (RRM) and true resistivity modulus (TRM) were defined. Analytical models were developed based on RRM, TRM, and Archie’s equation for predicting formation resistivity factor (FRF) and resistivity index (RI) under overburden pressure conditions. The results indicated that overburden FRF is dependent on FRF at initial pressure (ambient FRF), RRM, and net confining pressure difference. RRM decreases with cementation factor and rock compressibility. The proposed FRF model was validated using 374 actual core data of 79 plug samples (31 sandstone and 48 carbonate plug samples) from three sandstone reservoirs and four carbonate reservoirs, measured under four to six different overburden pressures. The developed FRF model fitted the experimental data with an average relative error of 2% and 3% for sandstone and carbonate samples, respectively. Moreover, the applications and limitations of the models have been investigated and discussed. Further theoretical analysis showed that overburden RI is a function of RI at initial pressure, TRM, and net confining pressure difference. The developed models supplement resistivity measurements and can be applied to estimate FRF, RI, and saturation exponent (n) variations with overburden pressure.

OnePetro

doi: 10.30632/PJV64N3-2023a3

SPWLA

SPWLA-2023-v64n3a3

Petrophysics

Country:

North America > United States > Texas (0.93)
Europe (0.71)
Asia > Middle East (0.68)

Genre: Research Report > New Finding (0.68)

Industry: Energy > Oil & Gas > Upstream (1.00)

Oilfield Places:

North America > United States > Texas > Permian Basin > Yeso Formation (0.99)
North America > United States > Texas > Permian Basin > Yates Formation (0.99)
North America > United States > Texas > Permian Basin > Wolfcamp Formation (0.99)
(22 more...)

SPE Disciplines:

Reservoir Description and Dynamics > Reservoir Characterization > Exploration, development, structural geology (1.00)
Reservoir Description and Dynamics > Formation Evaluation & Management > Open hole/cased hole log analysis (1.00)

Technology: Information Technology (0.93)

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Utilizing Remote Sensing and Data Analytics Techniques to Detect Methane Emissions from the Oil and Gas Industry and Assist with Sustainability Metrics

Esparza, Á. E. (GHGSat Inc. (Corresponding author)) | Ebbs, M. (GHGSat Inc.) | De Toro Eadie, N. (GHGSat Inc.) | Roffo, R. (GHGSat Inc.) | Monnington, L. (GHGSat Inc.)

OnePetroJune, 2023

Summary The purpose of this paper is to provide additional information and insights gained on manuscript SPE-209980-MS, accepted for presentation at the 2022 Society of Petroleum Engineers Annual Technical Conference and Exhibition (Esparza et al. 2022). The energy sector has been identified as one of the main contributors to emissions of anthropogenic greenhouse gases. Therefore, sustainability in the sector is mainly associated with the advancement in environmental and social performance across multiple industries. Individual firms, particularly those belonging to the oil and gas (O&G) industry, are now assessed for their environmental, social, and governance (ESG) performance and their impact on climate change. To meet the different key performance indicators (KPIs) for corporate social responsibility (CSR) and ESG, the planning, development, and operation of O&G infrastructure must be conducted in an environmentally responsible way. Today, operators calculate their own emissions, which are typically self-reported annually, usually relying on emission factors to complement the lack of emission measurement data. This paper discusses how methane detection of O&G infrastructure using remote sensing technologies enables operators to detect, quantify, and minimize methane emissions while gaining insights and understanding of their operations via data analytics products. The remote sensing technologies accounted for in this paper are satellite and aerial platforms operating in tandem with data analytics, providing a scheme to support sustainability initiatives through the quantification of some ESG metrics associated with methane emissions. This paper presents examples of measurements at O&G sites taken with satellites and aircraft platforms, providing evidence of methane emissions at the facility level. A discussion of each platform and how they work together is also presented. Additionally, this paper discusses how these data insights can be used to achieve sustainability goals, functioning as a tool for ESG initiatives through the incorporation of analytical models.

OnePetro

doi: 10.2118/215818-PA

SPE

SPE-215818-PA

SPE Production & Operations

Country: North America > United States > Texas (0.47)

Genre:

Research Report (1.00)
Public Relations > Community Relations (0.66)

Industry: Energy > Oil & Gas > Upstream (1.00)

Oilfield Places:

North America > United States > Texas > Permian Basin > Yeso Formation (0.99)
North America > United States > Texas > Permian Basin > Yates Formation (0.99)
North America > United States > Texas > Permian Basin > Wolfcamp Formation (0.99)
(22 more...)

SPE Disciplines:

Health, Safety, Environment & Sustainability > Sustainability/Social Responsibility > Social responsibility and development (1.00)
Health, Safety, Environment & Sustainability > Environment > Climate change (1.00)
Health, Safety, Environment & Sustainability > Environment > Air emissions (1.00)

Technology: Information Technology > Data Science (1.00)

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Modelling of Hydraulic Fracturing Risk on Cement Sheath Integrity

Transient Pressure Interference During CO2 Injection in Saline Aquifers

Paradigm Shift in Conventional Hydraulic Fracturing - Emerging Fracturing Techniques Using Thermochemical Fluids

Visualization of Surfactant Flooding in Tight Reservoir Using Microfluidics

Numerical Investigation of the Primary Mechanisms Leading to Complex Fracture Morphology in the Near-Wellbore Region

Feasibility Evaluation of Warm Solvent Assisted Gravity Drainage Process in Low-Carbon Developing Super-Heavy Oil or Oil Sands Project

Machine-Learning Based Selection of Candidate Wells for Extended Shut-In Due to Fluctuating Oil Prices

Shale Characterization Using T1-T2* Magnetic Resonance Relaxation Correlation Measurement at Low and High Magnetic Fields

Analytical Models for Predicting the Formation Resistivity Factor and Resistivity Index at Overburden Conditions

Utilizing Remote Sensing and Data Analytics Techniques to Detect Methane Emissions from the Oil and Gas Industry and Assist with Sustainability Metrics

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