Petrophysics – The SPWLA Journal of Formation Evaluation and Reservoir Description最新文献

{"title":"Holistic Evaluation of Reservoir Oil Viscosity in Breidablikk Field – Including Mud Gas Logging Approach","authors":"A. Cely, Ingvar Skaar, Tao Yang","doi":"10.30632/pjv64n6-2023a8","DOIUrl":"https://doi.org/10.30632/pjv64n6-2023a8","url":null,"abstract":"Breidablikk is a green field on the Norwegian Continental Shelf that just started the preproduction drilling of 23 wells in two structures. We have two reservoir fluid samples from exploration wells in each structure with relatively high viscosity of 4 and 8 cP, respectively. Our dynamic reservoir simulations on the Breidablikk Field indicate that any change in the viscosity in each direction can lead to a 20 to 30% difference in oil recovery. Therefore, updating our reservoir models with the viscosity distribution in the field along with the drilling activities is important. Currently, our models assume homogeneous reservoir oil viscosities across each structure. In this study, our primary aim is to conduct a holistic evaluation of the reservoir oil viscosity, using multiple methods to determine the most effective approach for qualitatively mapping the oil viscosity across the field, distinguishing between the low- and high-viscosity regions. The technologies chosen for this assessment are standard mud gas data, advanced mud gas data, and analysis of oil extracts from cuttings, given they have previously demonstrated their capability to estimate fluid properties while drilling or within a limited time frame, as evidenced by the work of Cutler et al. (2022). The methods were compared using pressure/volume/temperature (PVT) measurements as a benchmark. As of today, this method is considered the most reliable to obtain reservoir fluid properties, and in consequence, these measurements serve as the reference viscosity values in the study. The results of our analysis in Breidablikk show that an approach based on advanced mud gas data provide an oil quality classification that distinguishes between high- and low-viscosity reservoir oils, using the ethane/n-pentane ratio as the best parameter correlated to reservoir oil viscosity in Breidablikk. The threshold for the two viscosity regions is identified from a reservoir fluid database from the Breidablikk-Grane area, and the oil viscosity region estimated from advanced mud gas data agrees well with the PVT measurements. The viscosity estimation using a standard mud gas approach based on methane to propane compositions indicates that this technology cannot correctly differentiate between low- and high-viscosity region wells in the Breidablikk Field. Hence, it is not recommended. Further findings from our analysis indicate that the utilization of oil-based mud, combined with a high drilling speed, significantly affects the quality of the cuttings in Breidablikk. Consequently, the application of traditional geochemical analysis methods on cutting extracts is challenging. Therefore, this method is not recommended for the qualitative identification of the viscosity region of a given well. Benchmarking all available technologies allows us to select a real-time, reliable, and cost-efficient method to qualitatively estimate reservoir oil viscosity in Breidablikk. The selected method is field-specific and not ge","PeriodicalId":170688,"journal":{"name":"Petrophysics – The SPWLA Journal of Formation Evaluation and Reservoir Description","volume":"41 5","pages":""},"PeriodicalIF":0.0,"publicationDate":"2023-12-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"138626438","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":0,"RegionCategory":"","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}

{"title":"A Universal Data Format for Wellbore Logs","authors":"Tom Bradley, Simon Austin, David Holbrough, Warren Fernandes, Xuandong Wang, Gleb Dyatlov, Arnt H. Veenstra","doi":"10.30632/pjv64n6-2023a1","DOIUrl":"https://doi.org/10.30632/pjv64n6-2023a1","url":null,"abstract":"This paper describes a proposed high-specification standard format that is ideally suited for the data management of definitive records of wellbore logs. For this reason, it is a good standard for data exchange between applications. The format is suitable for complex three-dimensional (3D) data, including those generated by deep azimuthal resistivity (DAR) and ultradeep azimuthal resistivity (UDAR) tools, acoustic borehole reflection images, vertical seismic profiles (VSP), borehole imaging tools, multifingered caliper logs, and array data with multiple depths of investigation. It is applicable for use with logging-while-drilling (LWD) and wireline-conveyed logging tools. The format also naturally collapses down when utilized to store simple conventional logs that contain one value per depth in the wellbore. The proposed format provides spatial details of every data point collected by or interpreted from a wellbore-logging tool. The position of each data point is defined by reference back to the measure point of the sonde, which in turn is defined by the wellbore deviation survey and its coordinate reference system (CRS). Each data point in space may have an unrestricted number of parameters. An example might be most likely horizontal and vertical resistivity, maximum value based on uncertainty, minimum value based on uncertainty, and flags indicating the data position with respect to depth of detection (DOD). The new proposed format is so versatile. It is suitable as an Open Group Open Subsurface Data UniverseTM (OSDUTM) standard to store and exchange all data measured by logging tools in a wellbore and can possibly be extended to include all well data (for example, core, cuttings, and more). The proposed format requires a detailed definition so that computer scientists can implement it in applications used for subsurface modeling. The OSDU will also require this detailed definition in order to adopt it as a standard.","PeriodicalId":170688,"journal":{"name":"Petrophysics – The SPWLA Journal of Formation Evaluation and Reservoir Description","volume":" 30","pages":""},"PeriodicalIF":0.0,"publicationDate":"2023-12-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"138616128","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":0,"RegionCategory":"","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}

{"title":"Effect of Predisolved Natural Gas on CO2 Solubility in Water With Various Salinities at Reservoir Conditions","authors":"Jie Wang, Christine Ehlig-Economides","doi":"10.30632/pjv64n6-2023a11","DOIUrl":"https://doi.org/10.30632/pjv64n6-2023a11","url":null,"abstract":"Dissolution of CO2 in saline waters is considered one of three main CO2 trapping mechanisms, along with structural/stratigraphic trapping and mineralization. CO2 can dissolve in fresh/saline water under typical reservoir pressure and temperatures. Its solubility is dependent on pressure, temperature, and salinity. CO2 solubility studies typically consider saline water or fresh water as a liquid without any predissolved gases. The reality is formation water may contain appreciable dissolved gases for all pressure and temperature conditions. An example of gas-water ratio (GWR) can be ~1 scf/stb for formation water in an oil reservoir and ~5 to 6 scf/stb for a deep saline aquifer. Therefore, it is essential to quantify the effect of brine salinity on CO2 solubility in “live” saline waters. Just as “live” oil denotes reservoir oil that contains solution gas, we define “live” brine as saline water that includes dissolved gases. Conversely, “dead” brine refers to saline water devoid of any dissolved gas content. Two sets of experiments were conducted under typical reservoir conditions. The first set of experiments evaluated the CO2 solubility in live formation water. The second set of experiments evaluated how variation in the live brine salinity affected CO2 solubility. These experiments involved 1) synthesis of the brine, 2) synthesis of natural gas mixture, 3) recombination of live formation water with a natural gas mixture and transfer into a high-pressure and high-temperature pressure-volume-temperature (PVT) visual cell, 4) CO2 addition to the PVT cell, and 5) bubblepoint pressure determination within the PVT cell. The results showed that CO2 solubility in live formation water is significantly less than that in “dead” water under reservoir conditions. In addition, the brine salinity affects CO2 solubility in live formation water by further reducing CO2 solubility with increasing live brine salinity. As the brine salinity increases, very little CO2 can be dissolved in the live brine once it reaches a certain solubility. An understanding of CO2 dissolution in live saline water is essential for future CCUS evaluation and execution.","PeriodicalId":170688,"journal":{"name":"Petrophysics – The SPWLA Journal of Formation Evaluation and Reservoir Description","volume":" 91","pages":""},"PeriodicalIF":0.0,"publicationDate":"2023-12-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"138620553","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":0,"RegionCategory":"","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}

{"title":"Learnings From Impact and Implications of Signal-To-Noise in NMR T1-T2 Logging of Unconventional Reservoirs","authors":"Olabode Ijasan","doi":"10.30632/pjv64n6-2023a4","DOIUrl":"https://doi.org/10.30632/pjv64n6-2023a4","url":null,"abstract":"We study the impact of signal-to-noise ratio (SNR) on nuclear magnetic resonance (NMR) T1-T2 maps across data sets acquired in multiple wells of an unconventional field under various logging and processing conditions. The mean and standard deviation of NMR porosity error between continuous moving-pass and stationary measurements are used to obtain insights into the impact of SNR on accuracy and precision. In a proof-of-concept experiment, we introduce a novel semi-analytical smeared-peak (SASP) technique that compensates for the over-regularized smearing due to poor SNR, of T1-T2 relaxation responses of different fluids. The SASP approximation to de-smear volumes of different fluid types is validated with field measurements from multiple wells. The uplift of the SASP technique in improving fluid volume interpretations is apparent in the in-situ calibration of low-SNR moving-pass NMR measurements with high-quality stationary measurements. The learnings show that logging protocols that are designed to increase SNR by combining specific acquisition parameters with processing strategies, within acceptable compromises, are mandatory for reliable NMR characterization of unconventional reservoirs.","PeriodicalId":170688,"journal":{"name":"Petrophysics – The SPWLA Journal of Formation Evaluation and Reservoir Description","volume":" 61","pages":""},"PeriodicalIF":0.0,"publicationDate":"2023-12-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"138612223","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":0,"RegionCategory":"","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}

{"title":"Assessment of Depth of Mud-Filtrate Invasion and Water Saturation Using Formation-Tester Measurements: Application to Deeply Invaded Tight-Gas Sandstones","authors":"M. Bennis, Tarek S. Mohamed, C. Torres‐Verdín, G. Merletti, Camilo Gelvez","doi":"10.30632/pjv64n6-2023a9","DOIUrl":"https://doi.org/10.30632/pjv64n6-2023a9","url":null,"abstract":"Formation pressure/fluid measurements are impacted by mud-filtrate invasion, which may require long fluid pumpout durations to acquire hydrocarbon samples with minimal mud-filtrate contamination. However, unlike other well-logging instruments, formation testers do not have a fixed depth of investigation that limits their ability to pump out mud filtrate until acquiring original formation fluids (i.e., sensing the uninvaded zone). We use an in-house petrophysical and fluid-flow simulator to perform numerical simulations of mud-filtrate invasion, well logs, and formation-tester measurements to estimate the radial distance of invasion and the corresponding radial profile of water saturation. Numerical simulations are initialized with the construction of a multilayer petrophysical model. Initial guesses of volumetric concentration of shale, porosity, water saturation, irreducible water saturation, and residual hydrocarbon saturation are obtained from conventional petrophysical interpretation. Fluid-flow-dependent petrophysical properties (permeability, capillary pressure, and relative permeability), mud properties, rock mineral composition, and in-situ fluid properties are obtained from laboratory measurements. The process of mud-filtrate invasion and the corresponding resistivity and nuclear logs are numerically simulated to iteratively match the available well logs and estimate layer-by-layer formation water saturation. Next, using our multiphase formation testing simulator, we numerically simulate actual fluid sampling operations performed with a dual-packer formation tester. Finally, we estimate irreducible water saturation by minimizing the difference between the hydrocarbon breakthrough time numerically simulated and measured with formation-tester measurements. The examined sandstone reservoir is characterized by low porosity (up to 0.14), low-to-medium permeability (up to 40 md), and high residual gas saturation (between 0.4 and 0.5). The deep mud-filtrate invasion resulted from extended overbalanced exposure to high-salinity water-based mud (17 days of invasion and 1,800 psi overbalance pressure) coupled with the low mud-filtrate storage capacity of tight sandstones. Therefore, the uninvaded formation is located far beyond the depth of investigation of resistivity tools, whereby deep-sensing resistivities are lower than those of uninvaded formation resistivity. Through the numerical simulation of mud-filtrate invasion, well logs, and formation-tester measurements, we estimated radial and vertical distributions of water saturation around the borehole. Likewise, we quantified the hydrocarbon breakthrough time, which matched field measurements of 6.5 hours. The estimated radius of invasion was approximately 2.5 m, while the difference between estimated water saturation in the uninvaded zone and water saturation estimated from the deep-sensing resistivity log was approximately 0.13, therefore improving the estimation of the original gas in place.","PeriodicalId":170688,"journal":{"name":"Petrophysics – The SPWLA Journal of Formation Evaluation and Reservoir Description","volume":"4 3","pages":""},"PeriodicalIF":0.0,"publicationDate":"2023-12-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"138626126","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":0,"RegionCategory":"","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}

{"title":"Application of GAN to Resolution Enhancement of LWD Real-Time Image Logs to Support Decision Making","authors":"W. Trevizan, Candida Menezes de Jesus","doi":"10.30632/pjv64n6-2023a6","DOIUrl":"https://doi.org/10.30632/pjv64n6-2023a6","url":null,"abstract":"In the current scenario of project management, where the agility and optimization of operations have been prioritized, the practice of logging while drilling (LWD) has gained space compared to traditional wireline logging. In theory, acquiring quality petrophysical properties during drilling brings greater agility in decision making about completion and optimizes operation costs. However, regarding borehole image logs, due to limitations in transmission capacity, the actual available data in real time contain about 50% (for resistivity images) of the full azimuth information, being insufficient for the identification of critical geological structures capable of impacting the communication between production or injection zones or the quality of cementation, such as fractures, caves, and geomechanical collapse zones. The tool’s memory data with the full information may take a few days after the end of drilling to be delivered by the service company, which in some cases is not enough for fast decision making regarding completion. In this work, we tested models based on generative adversarial neural networks (GANs) to reconstruct the complete memory data based on real-time input. As in conventional GAN schemes, a generator is trained to receive a real-time input and create a “memory-like” image, while a discriminator is trained to tell real and fake images apart. To regularize the convergence of training, we used an architecture known in the literature as CycleGAN, where another generator-discriminator pair is trained simultaneously to do the reverse process, recreating the real-time data. Variations of the training process and data sets were used to generate different CycleGAN models. They were trained using logs of presalt reservoirs in Buzios Field, and performance was assessed on logging intervals not seen by the algorithms during training. The results achieved so far have been very promising, as in certain intervals, resultant models were able to capture the presence of fractures and caves. This methodology represents a way of circumventing telemetry limitations, where missing information is added indirectly to the real-time data as the artificial intelligence (AI) algorithm learns the main characteristics of a field/reservoir. Therefore, previous knowledge from the field can be used to continuously optimize future operations, efficiently incorporating the available database into the workflow of petrophysicists for the recognition of geological and geomechanical structures in time to support decision making in completion operations.","PeriodicalId":170688,"journal":{"name":"Petrophysics – The SPWLA Journal of Formation Evaluation and Reservoir Description","volume":" 83","pages":""},"PeriodicalIF":0.0,"publicationDate":"2023-12-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"138612027","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":0,"RegionCategory":"","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}

{"title":"Evolution of Casedhole Nuclear Surveillance Logging Through Time","authors":"D. Fitz","doi":"10.30632/pjv64n4-2023a1","DOIUrl":"https://doi.org/10.30632/pjv64n4-2023a1","url":null,"abstract":"Nuclear logging techniques have played a critical role in the evaluation and\u0000 surveillance of hydrocarbon reservoirs since the introduction of the gamma ray log in\u0000 1939. This paper reviews the history of key developments in nuclear logging that led to\u0000 improved methods to identify gas-oil (GOC), gas-water (GWC), and oil-water (OWC)\u0000 contacts in steel-cased wells, as well as methods to identify gas, steam, and waterflood\u0000 front encroachment, calculate their saturations, and recognize problems in efficient\u0000 reservoir depletion. This paper will focus solely on nuclear methods used to directly\u0000 identify fluids behind pipe using natural gamma radiation, neutron-induced gamma\u0000 radiation, and neutron flux measurements. This includes gamma ray, spectral gamma ray,\u0000 single- and dual-detector neutron measurements, pulsed-neutron capture, (), and\u0000 pulsed-neutron spectroscopy (carbon/oxygen or C/O) methods. It will not cover other\u0000 methods of identifying fluids behind pipe, such as borehole gravity and deep\u0000 electromagnetic (EM) methods using wired pipe. It also will not cover indirect methods\u0000 to infer fluid types in reservoirs, such as nuclear production logging using gamma\u0000 density and pulsed-neutron measurements.","PeriodicalId":170688,"journal":{"name":"Petrophysics – The SPWLA Journal of Formation Evaluation and Reservoir Description","volume":"58 1","pages":"0"},"PeriodicalIF":0.0,"publicationDate":"2023-08-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"123444167","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":0,"RegionCategory":"","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}

{"title":"Fracture Imaging and Response Characterization of the High-Definition Oil-Based Mud\u0000 Borehole Imagers Through Modeling and Inversion","authors":"Yong-hua Chen, Tianhua Zhang, R. Bloemenkamp, Lin Liang","doi":"10.30632/pjv64n4-2023a4","DOIUrl":"https://doi.org/10.30632/pjv64n4-2023a4","url":null,"abstract":"The new-generation, high-definition oil-based mud borehole imagers measure button\u0000 impedances, which are often inverted to produce images of the formation resistivity,\u0000 formation permittivity, and sensor standoff. These images, each reflecting a unique\u0000 aspect of the downhole media, can provide a comprehensive understanding of the\u0000 reservoir’s secondary porosity, i.e., fractures and vugs. To understand and validate the\u0000 inversion behavior on fractures and vugs, synthetic logs of axisymmetric 2D fractures\u0000 and vugs are generated and inverted. While the inverted medium properties follow the\u0000 variation of the fracture-filling materials, the inverted standoff is shown to be a\u0000 reliable indication of the fracture open/closed conditions. Specifically, an increased\u0000 inverted standoff would always appear for mud-filled open fractures, which is further\u0000 validated by laboratory measurements on artificial fractures and vugs. Numerical tests\u0000 indicate that mineral-filled fractures may also lead to some variations on the inverted\u0000 standoff when the resistivity contrast between the mineral-filling material and the host\u0000 formation is high. Therefore, an elevated standoff may also be associated with a\u0000 mineral-filled fracture. The modeling and inversion help reveal the connection between\u0000 the response of the inverted parameters and the actual fracture characteristics. When\u0000 the fractures are open and filled with mud, the inversion obtains an equivalent standoff\u0000 at the fractures. This equivalent standoff increases not only with fracture width but\u0000 also with the resistivity of the host formation. As a result, a fracture may have\u0000 varying amplitudes in different formation layers. The fracture modeling and inversion\u0000 also allow us to understand the prevalent existence of conductive fractures observed in\u0000 the field. It is commonly thought that the resistivity of oil-based mud is always higher\u0000 than that of the formation. However, this is only true at traditional operating\u0000 frequencies. Because of mud dispersion, the mud resistivity is different at the two\u0000 operating frequencies. For an open, mud-filled, resistive fracture to turn conductive,\u0000 the formation resistivity only needs to exceed the mud resistivity at the higher\u0000 operating frequency, which is typically on the order of a few 100 Ω·m instead of many\u0000 1,000 Ω·m at the lower operating frequency. As a result, an open fracture could be\u0000 easily conductive in one layer but resistive in another formation layer.","PeriodicalId":170688,"journal":{"name":"Petrophysics – The SPWLA Journal of Formation Evaluation and Reservoir Description","volume":"41 1","pages":"0"},"PeriodicalIF":0.0,"publicationDate":"2023-08-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"131793000","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":0,"RegionCategory":"","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}

{"title":"Mineralogical Modeling and Petrophysical Properties of the Barra Velha Formation,\u0000 Santos Basin, Brazil","authors":"M. Jácomo, G. Hartmann, T. B. Rebelo, N. H. Mattos, A. Batezelli, E. Leite","doi":"10.30632/pjv64n4-2023a3","DOIUrl":"https://doi.org/10.30632/pjv64n4-2023a3","url":null,"abstract":"The Santos Basin, offshore Brazil, has the most significant petroleum carbonate\u0000 reservoir province in South America. The presalt carbonates reservoirs of the Barra\u0000 Velha Formation (BVF) present a complex mineralogic distribution and heterogeneous\u0000 physical properties, making it challenging to construct a reliable mineralogical model.\u0000 Understanding rock mineralogy is important to petroleum prospects and the study of\u0000 porous media, besides calibrating seismic facies. In this paper, we present a\u0000 mineralogical inversion procedure to model reservoir and nonreservoir intervals within\u0000 the BVF in a presalt field applying multicomponent inversion. The uppermost 15 to 28 m\u0000 of the BVF, known as “Lula Fingers,” present higher values of gamma ray when compared\u0000 with deeper intervals and are characterized by high modeled dolomite contents. Below the\u0000 Lula Fingers region, the Upper BVF can be divided into BVF100 (top), which is\u0000 characterized by low gamma ray values just above the BVF200 (bottom). They are formed\u0000 mainly by shrub and spherulite-rich in-situ facies with fewer clay and Mg-clays\u0000 contents, which are often replaced by dolomite and quartz. The bottom part of Upper BVF\u0000 (BVF200) presents a microporous Mg-clay-rich interval, mainly in the structural flanks\u0000 region, or a macroporous Mg-clay-poor interval, mainly in high levels. The present model\u0000 fits well with the stratigraphic interval and allows a better understanding of the\u0000 mineralogical distribution over the entire BVF100 and BVF200, particularly the lateral\u0000 mineralogical variability in regions with structural highs and flanks.","PeriodicalId":170688,"journal":{"name":"Petrophysics – The SPWLA Journal of Formation Evaluation and Reservoir Description","volume":"64 1","pages":"0"},"PeriodicalIF":0.0,"publicationDate":"2023-08-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"126390307","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":0,"RegionCategory":"","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}

{"title":"Python Dash for Well Data Validation, Visualization, and Processing","authors":"Yuchen Jin, Chicheng Xu, Tao Lin, Weichang Li, Mohamed Larbi Zeghlache","doi":"10.30632/pjv64n4-2023a6","DOIUrl":"https://doi.org/10.30632/pjv64n4-2023a6","url":null,"abstract":"Open-source Python libraries play a critical role in facilitating the digital\u0000 transformation of the energy industry by enabling quick deployment of intelligent\u0000 data-driven solutions. In this paper, we demonstrate an example of using Dash, a Python\u0000 framework introduced by Plotly for creating interactive web applications. A\u0000 fit-for-purpose software was tailored for an in-house research project in well-data\u0000 validation, visualization, and processing. The application automates quality control of\u0000 different sets of well-log data files (DLIS/LIS or LAS) for completeness, validity, and\u0000 repeatability. For this tedious and critical process, a human expert is required to\u0000 perform tasks using well-log interpretation software. A typical digital log file may\u0000 contain hundreds or thousands of data channels that are difficult are difficult to\u0000 visualize and validate manually. Sometimes it takes multiple iterations of communication\u0000 between the data provider and the data receiver to achieve a final valid deliverable\u0000 copy. By utilizing open-source Python libraries, such as DLISIO (Equinor ASA, 2022) and\u0000 LASIO (Inverarity, 2023), a web interface based on Plotly-Dash is developed to visualize\u0000 and check all data channels automatically and then produce a compliance summary report\u0000 in PDF or HTML format. The time for validating one DLIS file that has hundreds of data\u0000 channels is significantly reduced. Implementation of this automated data quality control\u0000 workflow demonstrates that open-source Python libraries can significantly reduce the\u0000 time from development to the deployment cycle. Quick implementation of intelligent\u0000 software based on Python Plotly-Dash enables customized solutions or workflows that\u0000 further improve both the effectiveness and efficiency of routine data quality control\u0000 processes.","PeriodicalId":170688,"journal":{"name":"Petrophysics – The SPWLA Journal of Formation Evaluation and Reservoir Description","volume":"7 1","pages":"0"},"PeriodicalIF":0.0,"publicationDate":"2023-08-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"129184643","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":0,"RegionCategory":"","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}