bluuebunny/crossref_metadata_2025_split huggingface dataset:
Unsupervised Deep Learning for Facies Pattern Recognition on Borehole Images
Authors: Lima Laura , Bize-Forest Nadege , Evsukoff Alexandre , Leonhardt Renata 
Published: October 2019

Abstract
This paper proposes an unsupervised neural network model for facies pattern recognition and formation characterization using borehole images. The goal is to create an automated workflow for rock fabric identification using high resolution acoustic or electrical borehole images with the aim of supporting 3D geological modeling. The results are compared and validated with geological and petrophysical interpretation.
Image-based facies recognition is challenging when applying Deep Learning techniques: 1/ the volume of released labeled data constrains the abilities to build a robust neural network model 2/ data classification itself is subject to geologist interpretation. Additionally, indirect measurements can bias data, hindering the correlation between log response and any particular classification.
We propose, therefore, an application of a fully convolutional autoencoder for borehole image data clustering to extract the most representative information displayed by the images without relying on labeled data.
The data set corresponds to electrical borehole images with high-resolution at 0.2in and 80% borehole coverage. First, we apply an autoencoder reconstruction loss for network pre-training, then a joint training using cluster assignment hardening. After training and applying the model, patterns represented by each cluster of geological facies or geomechanical features constitute a library that can be assigned by the user to specific facies or can be automatically correlated to the core description. The method provides pattern recognition and facies prediction with higher resolution and accuracy than conventional Machine Learning methods based on the clustering of petrophysical properties.
Asphaltene Structural Changes Induced by Carbon Dioxide Injection
Authors: Golshahi Nikoo , Afra Salar , Samouei Hamidreza , Nasr-El-Din Hisham , Beraldo da Silveira Balestrin Lia 
Published: October 2019

Abstract
Asphaltenes precipitation during carbon dioxide injection to enhance recovery has been considered as one of the major challenges in the tertiary production phase. How CO2 would change the asphaltenes structure is still unknown. The present study investigates the effects of CO2 on the isolated asphaltenes by means of various analytical techniques. Chemical structure of precipitated asphaltenes in the presence and absence of CO2 were characterized and compared. These results were coupled with the results of the stability assessment to determine the effects of structural alteration on asphaltenes stability in the oil matrix.
Four different crude oils were used to implement this experiment. In the first step, asphaltenes were precipitated by n-heptane. The asphaltenes were then dissolved in toluene and CO2 was injected (at 870 psi) to these solutions and they were mixed at 752°F. This process was repeated for three days, and one week to identify the effect of time on the possible reaction between CO2 and asphaltenes at elevated temperature and pressure. Next, CO2 was injected to the crude oils to determine whether it would react with other components of the oils other than asphaltenes. Same procedures were repeated with nitrogen as controlling experiments. For characterization, Fourier Transform Infrared Spectroscopy (FTIR spectroscopy) was conducted to specify the functional groups and their changes due to the addition of CO2. Finally, stability alteration of precipitated asphaltenes after reaction with CO2 was evaluated by UV-Vis spectroscopy.
FTIR results analyses demonstrated that in one tested sample the peak related to the amide functional group is created after injecting CO2. This peak was intensified by increasing the reaction time. To characterize the origin and mechanism of amide formation, 1,4-diazabicyclo[2.2.2]octane (DABCO) was added to this asphaltenes sample during reaction with CO2. Neither escalation of carbonyl group nor generation of aldehyde functional group was detected in the presence of DABCO. Such an observation proves that the amide group was formed by the reaction of amine in the asphaltenes and CO2. The stability of this sample in model oil was decreased after reaction with CO2. On the contrary, FTIR spectrums of the other three samples were not altered after reaction with CO2. Interestingly, one of these three asphaltenes samples became unstable in the model oil after reaction with CO2.
This study shows that the asphaltenes instability in the presence of CO2 could be a consequence of either chemical structural alteration of asphaltenes or change of the oil matrix solubility. Hence a comprehensive characterization of an oil sample is essential before designing any CO2 injection treatment. Accordingly, these results can be utilized to select more efficient inhibitors and stabilizers to prevent asphaltenes precipitation.
Improved Digital Rocks-Based Model for NMR Permeability Estimation in Vuggy Deepwater Carbonates
Authors: Victor Rodolfo Araujo , Torres-Verdín Carlos , Prodanovic Masa 
Published: October 2019

AbstractWe introduce a new digital rocks-based method for interpreting NMR T2 distributions in well log data acquired in vuggy deep-water carbonate reservoirs. Our method accounts for adverse borehole conditions such as mud invasion and large washouts in vuggy zones, usually neglected in conventional interpretation procedures of NMR logs.The new approach is based on describing the measured distribution of transverse relaxation times as the superposition of a finite set of log-normal components. Each component accounts for specific relaxation rates for drilling mud and original formation fluids. We carefully design our NMR interpretation model after processing whole core X-ray computed tomography (CT) images acquired in whole core samples. Estimation of density and atomic number from dual-energy CT data enabled to directly probe fluid content in the vuggy space, while image segmentation targeting the vuggy space allowed to estimate vuggy porosity and flow properties inside the vug network.Our model was able to explain correlated anomalies shown by caliper, photoelectric, and NMR T2 logarithmic mean logs for the vuggy regions in the dataset studied. The decomposition of inverted NMR T2 distributions in a set of basis functions naturally handles the uncertainty related to inversion parameters, making the task of calculating fluid concentrations and permeability indices more robust with respect to small variations in cutoff values. Permeabilities in vuggy zones estimated from NMR logs using this new method are more accurate than those rendered by conventional techniques based on T2 cutoffs or logarithmic averages, without the need to artificially introduce new fitting parameters. Using this approach, we can also explicitly quantify vuggy porosity, which is in good agreement with values obtained from segmented whole core tomographic images for this particular dataset.The combined use of the above interpretation methods confirms the value of digital rock techniques to improve the evaluation of well logs acquired in complex carbonate formations, specifically in the calculation of permeability across vuggy depth segments. Results can be used to improve well log interpretation in wells devoid of core data and/or high-resolution borehole images.
Recent Developments in Polymer Flooding for Carbonate Reservoirs under Harsh Conditions
Authors: Diab Waleed N. , Al-Shalabi Emad W. 
Published: October 2019

AbstractPolymer flooding is one of the well-established and commercially-available techniques for enhanced oil recovery in the petroleum industry. It is the most widely adopted chemical enhanced oil recovery technique in sandstones, but its application in carbonates is limited due to the harsh reservoir conditions of high temperature, high salinity, and low permeability. However, research is advancing to expand the applicability of this technique to carbonate reservoirs in a cost effective manner. In this paper, we present a comprehensive review on polymer flooding for carbonates under harsh conditions. This review includes descriptions of underlying mechanisms, polymer types, polymer screening studies, coreflood laboratory work, numerical and modeling works, and field applications. Screening of new polymers for potential field applications is also discussed. In addition, polymer rheology and challenges posed to polymer flow in the porous media are described. Moreover, summary tables of different monomers used to tailor polymers for harsh conditions as well as temperature and salinity limits of different polymers are provided, which makes this review as a guidance for implementing new projects using the polymer flooding technique.The literature review conducted shows that with the recent technology, a field-scale application of polymer flooding in carbonate reservoirs is possible. Several polymer types have been recently developed to overcome harsh carbonate conditions of high temperature, high salinity, and low permeability. This is encouraging towards conducting pilots in carbonate reservoirs in a cost effective manner. At the end of this paper, recommendations to overcome the challenges of high temperature, high salinity/hardness, and poor injectivity are provided based on this vast literature review and our experiences in polymer flooding. This paper gives more insight into polymer flooding aspects and its different applications in the oil industry. In addition, the study is considered as a guide for starting or implementing potential projects on polymer flooding in carbonate reservoirs under harsh conditions.
Challenges with Production Sharing Contracts in Brazil: What the International Experience and Literature Review Can Tell Us?
Authors: Medeiros Breno Barreto , Britto Renata , Barsan Flaviu 
Published: October 2019

Abstract
Following the discovery of the giant Pre-salt play in Brazil in 2006, the Government implemented a new fiscal regime in 2010, namely the Production Sharing Contract (PSC), for the exploration and production of oil and gas in this area. The introduction of the PSC regime brought about challenges and uncertainties on the day-to-day activities for all stakeholders involved. In this context, the objective of this article is to highlight the main challenges faced by the industry participants in Brazil, based on international experiences and literature review. Concurrently, the paper adds more clarity on areas where, in practice, we expect the majority of these risks to materialize, such as the design, implementation and operation of PSCs, with a view to investigate the main challenges related to the implementation of PSCs. Most notably, the article addresses the resource and competency requirements that regulators and oil companies alike require to enable an accurate and compliant recovery of eligible costs. We focus our international experience analysis on Indonesia, a jurisdiction with a mature oil industry, which pioneered the cost recovery PSC model, and draw learnings from the premises and results of recent changes in the Indonesian fiscal regime, as documented in industry publications. Moreover, the article attempts to quantify the financial impact on oil companies for not recognizing all recoverable costs and the magnitude of government revenue losses arising from poor cost discipline or gold plating behaviors by offshore contractors. Conclusions are drawn on key improvements since the first pre-salt licensing round, when the terms of the PSC were considered relatively onerous and risky for investors. We also draw attention to the key factors which have enabled a more transparent and competitive bidding environment in the Pre-Salt in recent years, while allowing the Brazilian Government to maintain a significant share of revenues and control over the assets.
An Integrated WAG Characterization Study for an Offshore Oilfield
Authors: Vieira Raphael A. M. , Cardoso Marco Antônio , Pizarro Jorge O. S. 
Published: October 2019

AbstractWater-Alternating-Gas (WAG) injection is an enhanced recovery method that is being applied in some brazilian offshore oilfields as an alternative to combine effective pressure maintenance policies, flexible produced gas management strategies and increased recoveries. In this technology, gas plays the role of reducing residual oil saturation while water controls, by multiphase flow-in-porous-medium effects, gas adverse mobility.In addition to the extra engineering tasks needed to design development plans and production facilities, an intense characterization programme should be put in practice in order to reduce risks, increase predictability and optimize WAG floods. Much more complex laboratory tests than the ones usually performed for continuous water/gas floods should be done, particularly to tackle multiphase flow in porous medium phenomena. The proper characterization, modeling and simulation of these effects are vital for a representative WAG design and evaluation.This paper presents the results of a pragmatic and integrated laboratory characterization, modeling and simulation study for an offshore oilfield that was focused on relative permeability hysteresis effects.Firstly, it summarizes the best relative permeability hysteresis model (Larsen & Skauge) available in most commercial reservoir simulators. Then, it describes a special laboratory WAG multiphase flow-in-porous-media characterization program, designed and executed to obtain the parameters of this hysteresis model. Experiments were done at reservoir conditions and with rock and fluids from an actual offshore field. Following, results of these tests were evaluated in light of Larsen & Skauge model, in order to confirm its validity. Finally, WAG simulations of a sector of the target field were performed to access the impacts of including or neglecting relative permeability hysteresis phenomena.Conclusions of this work contribute to increase predictability and reduce uncertainties related to field-scale implementation of WAG technology. Knowledge acquired from this study promoted a better estimation of oil recovery, gas production and overriding. It also supports the design of subsea and topside equipment, which is critical in the offshore scenario.
Discovering Patterns within the Drilling Reports using Artificial Intelligence for Operation Monitoring
Authors: Colombo Danilo , Pedronette Daniel Carlos Guimarães , Guilherme Ivan Rizzo , Papa João Paulo , Ribeiro Luiz Carlos Felix , Sugi Afonso Luis Claudio , Presotto João Gabriel Camacho , Sousa Gustavo José 
Published: October 2019

Abstract
In well drilling activities, the execution of a sequence of operations defined in a well project is a central task. In order to provide proper monitoring, the operations executed during the drilling procedures are reported in Daily Drilling Reports (DDRs). Technologies capable of assisting the fulfillment of such reports represent valuable contributions. An approach using Machine Learning and Sequence Mining algorithms is proposed for predicting the next operation and classifying it based on textual descriptions.
Nowadays, artificial intelligence (AI) applications play a key role in digital transformation process and is a very broad area, with various branches. Machine Learning techniques provide systems the ability to automatically learn and improve from experience without explicit instructions. Sequence Mining can be broadly defined as the task of finding statistical relevant patterns between samples modeled in a sequence. In our approach, the operations reported in DDRs are analyzed by Sequence Mining algorithms for predicting the next operation, whereas Machine Learning methods are used for automatically classifying the operations according to predefined ontologies based on textual descriptions.
The proposed approach was experimentally validated using a real-world dataset composed of drilling reports with approximately 90K entries. Various sequence prediction algorithms are considered, more specifically: CPT+(Compact Prediction Tree+), DG (Dependency Graph), AKOM (All-k Order Markov), LZ78, PPM (Prediction by Partial Matching), and TDAG (Transitional Directed Acyclic Graph). For the classification tasks, approaches based on word embeddings and CRF (Conditional Random Fields) are exploited. Experimental results achieved high-accurate results, of 89% for the classification task. The promising results indicate that such strategies can be successfully exploited in the evaluated scenarios. Additionally, the positive results also encourage the investigation of its use in other oil and gas applications, since the reports organized through chronological order consists of a common scenario.
The main contribution to the oil and gas industry consists of using artificial intelligence strategies in tasks associated with DDRs, saving human efforts and improving operational efficiency. Although the Sequence Mining and Machine Learning algorithms have been extensively used in different applications, the novelty of our work consists in the use of such approaches on the tasks of extracting useful information from the DDRs.
Atlanta Field Development - Present and Future
Authors: Sergio Rocha Paulo , de Oliveira Goulart Roberto , Kawathekar Satyajeet , Dotta Raul 
Published: October 2019

Abstract
Heavy oil represents a significant portion of the remaining oil reserves and there are strong economic incentives within industry to develop technologies to profitably produce these oil reserves. The success of Early Production System phase (EPS) and Definitive System (DS) solutions for Atlanta Field development certainly presents a promising way forward to achieve a safe production of extra-heavy oil in deep waters.
As the Operator, Enauta made the farm-in of Atlanta Field in 2011. Atlanta is a heavy oil field with 14°API grade with viscosity equivalent of an oil with 12°API, a shallow reservoir around 800 meters below sea bed with low temperature of 40°C and water deep around 1,550 m. Heavy oils are often characterized by their high viscosities, stable emulsion formation tendency and low reservoir energy. These combined characteristics makes production, transportation and processing operations very challenging. Likewise, the Atlanta crude imposes enormous challenges for the characterization of the reservoir, drilling and completion, flow assurance from the wells to FPSO, topsides process ing (phase separation, heat and power generation methods) and cargo storage as well as offloading from the FPSO to tankers.
This paper describes EPS implementation and DS development to overcome these project challenges with the use of the best available technical solutions and approaches to keep production safe and profitable, focused on the specifics strategies to overcome flow assurance challenges, techniques employed for the fluid viscosity management and emulsion breaking, techniques to enhance phase separation, heat and power generation methods and fuel alternatives to optimize OPEX and various design features to reduce atmospheric emissions.
Production aspects will also be described from the solution adopted for the oil processing and offloading for the EPS FPSO as well as the DS "flex-FPSO" concept to enable oil production using alternative fuels, bearing in mind CAPEX/OPEX optimization, operational flexibility, robustness and ever tightening environmental regulations.
To ensure safe operations, different contingency plans have been implemented, like this innovative solution: a software developed and tested offshore to reliably predict the drift (SW-Drift) of the drilling ship for both forecast and real-time metocean data, to accurately determine the conditions under which a support vessel shall be aware in advance to avoid collision of the drilling ship caused by a possible blackout event.
The Atlanta Field development presents a successful real case to the Oil Industry to be considered in similar difficult oil and project conditions.
Gas to Wire as an Alternative to Natural Gas Monetization of the Pre-Salt Province in Brazil
Authors: Lima Mota de Lucas , Santos Baleeiro Diogo , Peixoto Cortez Breno 
Published: October 2019

Abstract
In a global context of an irreversible trend of decarbonization of the economy, natural gas plays a prominent role in the global commitment to reduce carbon indices, and its exploration will contribute to the transition of the world's electric and energy matrix. Brazil has enormous potential when it comes to natural gas, particularly in the pre-salt province, which is considered to be the largest oil discovery in the Southern Hemisphere in the last thirty years. If on the one hand, the pre-salt has a great potential for natural gas production, on the other, there are enormous technological and logistical challenges to enable the commercial use and monetization of this gas produced. In this context, the present work proposes to present a contribution to the study of the use of Gas to Wire (GTW) as a technological alternative for the use and monetization of the natural gas from pre-salt province. For that, a review of the specialized literature, including specific periodic data in O&G, and an economic evaluation of the use of GTW in the pre-salt province were carried out, comparing it with the concept of a GTW plant in an onshore environment. In an optimistic production scenario, and even with the expected expansion of the pre-salt gas flow line routes, the difference between the natural gas produced and the injected, burnt gas, used in the offshore site and outflow facilities, will be positive at 15 MMm3/day and will cause operators to seek alternatives for valuation of this resource, since if commercial use is not viable, operators will simply have to paralyze the development and production of their fields, whereas pre-salt natural gas is generally associated with oil. The GTW emerges an alternative technology for the utilization and monetization of natural gas across the inflexibility of gas production not associated with the pre-salt fields. The economic costs for deploying an offshore GTW system and the level of energy cost aiming the use of pre-salt natural gas were competitive accounting for 84% to 91% of the costs of generating a GTW plant in an onshore environment. The case study demonstrates that the concept of GTW can be economically viable, with limitations, such as technological alternative for the utilization and monetization of natural gas across the inflexibility of gas production not associated with the pre-salt fields.