bluuebunny/crossref_metadata_2025_split huggingface dataset:
From Geophone to DAS: Evolution of Q Estimation
Authors: Pierre Bettinelli , Le Calvez Joel 
Published: January 2020

The Schlumberger Oilfield Glossary states that Q is ‘the ratio of the peak energy of a wave to the dissipated energy. As waves travel, they lose energy with distance and time due to spherical divergence and absorption. Such energy loss must be accounted for when restoring seismic amplitudes to perform fluid and lithologic interpretations, such as amplitude versus offset (AVO) analysis’.
In surface seismic, we face the problem of characterizing the effect of anelastic attenuation on the seismic signal during propagation. The Q-factor is sought after because it is useful for amplitude analysis, phase compensation and for improving resolution. Though the Q-factor can be estimated from surface seismic data, traditionally the Q-factor is extracted using acquisition methods relying on accelerometers and/or geophones during borehole seismic surveys such as zero-offset vertical seismic profile (VSP), 2D walk-away VSP (2D WVSP) or 3D VSP campaigns. The reason why borehole seismic is the preferred option to estimate the Q-factor is because VSP surveys sample the wavefield by sensors in-situ (depth control), and also it gives robust measures using the direct arrivals. The Q-factor can then be, used to derive a Q-filter, which can be applied to the surface seismic to diminish the effect of anelastic attenuation and can compensate for the loss of amplitude and frequency in the data as well as to correct for the phase difference.
Several methods of Q-factor determination may be used, each with its pros and cons (e.g., continuous (log) Q-factor using spectral ratio, multi-spectral ratio, continuous interval Q-factor).
With recent advances in the fiber optic field, we anticipate (and already see) a surge in VSP surveys being acquired with distributed acoustic sensing (DAS) or heterodyne distributed vibration sensing (hDVS) as this acquisition method is extremely cost-effective from a deployment point of view and required acquisition time.
We demonstrate that with minimum work, one can provide a robust Q-factor estimation using fiber-acquired datasets.
Integrated Approach to Develop Mega-Projects: Challenges and Risk Strategies
Authors: Akimova Irina 
Published: January 2020

The ambition of this paper is to provide description of integrated approach that was successfully applied to develop mega-projects in Russia: from development of Yamal, the biggest gas provience in Russia and in the world with several unique super mega-fields located in the area, to the recent ahead-of-time Arctic development in Russia.
Russian oil and gas sector is characterized by high concentration of mega, super-giant and giant fields in two relatively small areas – Yamalo-Nenetskiy District as a gas provience and Khanty-Mansiysk District as an oil provience, which are very remote from the mainland with lack of infrastructure at the time when mega-projects were just a plan and hazardous climate conditions. Most of the territory of the Yamalo-Nenetskiy district is located above the Polar Circle that makes its development so challenging. The aim was not only to develop these oil and gas mega-projects and its infrastructure but to create and maintain high standard of living for local communities and indigenous nationalities. And this goal was successfully achieved by using special integrated approach. This special integrated approach combines territorial, industrial and mega-project joint planning and performing along with cost management of these projects including special agreements between regions and companies, trend that is very special still to the international energy market and this practice was followed by a number of international energy majors already. For the latest and even the most complicated mega-project now, Russian Arctic development, new updated integrated approach was elaborated that combines so called support zones of development, infrastructure development and emerging technologies development. New legislative framework and fiscal incentives along with special investment contracts were introduced to booster this project development and to attract investments. All the zones of development are considered as one project with common planning, financing, cost management and all the zone’s projects implementation.
Yamalo-Nenetskiy District (YANAO) contributes 18% to the world’s gas proved reserves and 65% to the Russia’s total gas reserves. As for the beginning of 2018, 236 fields of hydrocarbons were discovered in YANAO, from them 89 fields are under development now and 147 fields are under exploration works. Main area of gas production in YANAO is in Nadym-Pur-Taz oil and gas provience where world’s biggest concentration of super giant mega fields are located – Medvejie field, Urengoy field and Yamburg field. These fields were put into operation in 1970s-1980s and mainly in the declining production level now. Since the beginning of production in Yamalo-Nenetskiy District, totally 12% of initial gas reserves, 5% of oil and 2% of condencate were extracted. To maintain production level and to secure export contracts, new centers of production are under development now. Yamal’s peninsula development started in 2012 with the launch of the giant Bovanenkovo field.
Should We Waterflood Low Permeable Reservoirs?
Authors: Naugolnov Mikhail , Sednev Alexey 
Published: January 2020

The aim of work is to ensure that it is possible to realize effective water injection system for low permeable reservoir with hard-to-recover deposits and an average permeability less than 1 mD. The results of oil field pilot works and computer modelling are shown and compared.
The novelty of the work are rare enough field experiments in water injection system organization in low permeability reservoirs and injection system full comprehensive studding. Some empirical correlations between the values of permeability, heterogeneity, sweep efficiency and injection effectiveness for different well completion types will help reservoir engineers to select the best well pattern and to decide do we need any injection or not without labor intensive actions.
Effect of Temperature on Fines Migration during Water Disposal
Authors: Wang Yamin , Yu Muhan , Le-Hussain Furqan 
Published: January 2020

Recent experimental studies show that fines migration effect in sandstone rocks is more prominent at higher temperature. However, increased fines migration is generally attributed to temperature dependant zeta potential. In this study, laboratory studies were designed to investigate if mineral dissolution induced more fines migration at high temperatures.
In this experimental study, Berea sandstone core samples are used and performed single-phase flooding experiments at three temperatures, 25°C, 50°C and 70°C. Core samples are characterized using X-Ray Powder Diffraction (XRD) and X-Ray Fluorescence (XRF) before the flooding experiments. Scanning Electron Microscopy (SEM) and Energy Dispersive X-ray Spectroscopy (EDS) analysis are also conducted to identify the changes of rock surface before and after the flooding experiments. All core samples are subjected to single-phase injections of water at salinities 40, 10, 2.5, 0.5 and 0g/L NaCl. To calculate permeabilities, pressure drops are recorded using pressure transducer during the flooding experiments. The produced water is collected and used to measure the concentration of produced fines. Inductively coupled plasma-optical emission spectrometry (ICP-OES) is applied to analyze the types of produced minerals in each experiment.
The analysis of produced water showed that an increase in Ca ions at 50°C and 70°C. Chemical reation led to dissolution of carbonate minerals increasing pore opening. Therefore, the permeability damage due to fines migration is less pronounced at high temperatures.
De-Risking a Large-Scale Unconventional Gas Field Development
Authors: Khan Farooq , Elphick Matthew 
Published: January 2020

Unconventional gas developments in the Middle East are relatively new, compared to the established shale developments in the US. The Middle East developments are generally owned or controlled by a single entity, e.g. the national oil company, rather than the model often seen in the US of multiple operators focused on their particular ‘block’. This can lead to a different approach to the full field development (FFD), with more emphasis needed on de-risking projects, particularly during their early stages. This de-risking process is essential to limit the exposure of the single owner to the inherent uncertainties of an unconventional development as the scale of the project increases.
This paper considers multiple areas of uncertainty and risk associated with an unconventional gas field development. From the necessity for clear project drivers and team alignment, through to the uncertainties of well production and water management, risks are identified with recommendations to help projects avoid pitfalls and manage the inherent risks of developing a large unconventional field in the Middle East. The paper concludes that a Middle Eastern project can't, in all cases, simply adopt the practices used in the US. The project may choose to take guidance from the US but since the operating environment is different, the risks, and therefore management of risks, will in many cases need to be addressed differently.
State-of-the-Art Review of Lost Circulation Materials and Treatments – Part II: Probability and Cost Analyses
Authors: Alkinani Husam H. , Al-Hameedi Abo Taleb T. , Dunn-Norman Shari , Al-Bazzaz Waleed H. 
Published: January 2020

Lost circulation is a major problem in drilling operations. As the drilling environment is getting more complicated nowadays, the problem of lost circulation can lead to a significant additional non-productive time (NPT). The objective of this work is to provide in-depth insights into probability and cost analyses of the current lost circulation materials and treatments used around the world. This is the second part (Part 2) of the state-of-the-art lost circulation materials and treatment, the other part (Part 1) focuses on the trends and uses.
Lost circulation data of more than 2000 wells drilled worldwide were gathered from many sources such as daily drilling reports, final well reports, technical reports, petroleum literature, etc. The treatment data were classified based on the type of loss as treatments for partial, severe, and complete loss. Descriptive data analytics and visualization tools were used to analyze the data. A dashboard was created to help to analyze the data.
The results of this work revealed that there are simply two criteria to be used in the decision-making process to choose the best lost circulation treatment. The first one is that the treatment has to have a high probability of success, and the other criterion is that the treatment has to have a relatively reasonable cost based on the type of loss. In different words, optimization has to be conducted to choose treatments based on the type of loss. However, some treatments with a high probability of success may have a low number of usage which might be the reason behind the high probability of success. Thus, careful attention should be given for the number of uses of each treatment when calculating the probability. On the other hand, some treatments have a low probability of success and high cost, which indicates that the high cost does not always correlate with a high probability of success. In addition, the type of loss will play a major rule in selecting the treatments since some treatments are too expensive to be applied for partial loss as an example, and usually, other options are available.
In short, this study will provide clear insights into the cost and probability of the state-of-the-art lost circulation treatments and materials used in the oil and gas industry. The recommendations provided by this study can be utilized to make better future decisions to treat lost circulation.
Environmentally Acceptable Shale Inhibitors for High Performance Water-Based Muds
Authors: May Preston , Deville Jay , Miller Jeffrey , Burrows Kim 
Published: January 2020

The water reactivity of clay-containing shale minerals remains a long-standing problem when drilling wellbores with water-based fluid systems. Complicating this issue, the environmental effect of chemical additives used in water-based drilling fluids continues to receive heightened scrutiny in various regions across the world. This study addresses these challenges by expanding the molecular toolbox of environmentally friendly additives that are available to manipulate shale reactivity. To this end, a shale inhibitor package is introduced and discussed that leverages chemical synergy to impede the uptake of water in shale minerals while also increasing the structural integrity of shale cuttings. The main component, a natural-based hybrid organic/inorganic inhibitor blend, is highlighted.
Simple fluids systems were prepared with potassium-based brines and combined with shale inhibitors for initial shale erosion screening experiments. These simple fluids isolated the shale inhibition effects of the inhibitors of interest and excluded the possible influence of additional chemical additives typically found in drilling fluids. Subsequently, fully formulated, water-based drilling fluids were prepared with these inhibitors and compared to fluids with traditional inhibitors. These fully formulated drilling fluids were characterized by rheological testing, fluid loss, shale erosion, accretion, and linear swell testing.
An inhibitor combination of a hybrid organic/inorganic inhibitor blend, along with a nitrogen-rich oligomeric hydration suppressant, was determined to be the most effective inhibition mixture in simple fluid screening. The dual mode of action of the two inhibitors, disparate in both molecular size and chemistry, likely achieved optimal interfacial shielding on the clay minerals to effectively diminish the rate of reaction with water. More importantly, the shale inhibition was successfully translated to fully formulated fluid systems without affecting rheological properties or diminishing fluid loss control. The results achieved were comparable to a current high-performance, synthetic-based shale inhibitor; however, the new shale inhibitor package features a more favorable environmental profile.
Natural-based materials and their derivatives are continually revealed to contain useful properties, particularly for water-based drilling fluids. In this study, high-performance functionality and environmental friendliness were united with an innovative natural-based hybrid organic/inorganic inhibitor blend that is believed to function by encapsulating shale minerals. In addition, a synergy was discovered between hybrid organic/inorganic inhibitor blends and nitrogen-rich oligomeric compounds. Ultimately, the materials developed have achieved yellow environmental ratings in the North Sea and have been successfully validated in field applications in Norway.
Effectiveness Well Integrity Management for Casing Leak Detection Utilizing Temperature Profile in Offshore Oil Field
Authors: M. Al-Dhafeeri Abdullah , Fouad Abo Zkery Shebl , A. Al-Aklubi Sultan , Ahmed Al Sdeiri Saad 
Published: January 2020

As part of well integrity and safety campaigns in offshore fields, downhole Temperature surveys were obtained as record of temperature values measured with respect to depth steps (logs) in a well. The downhole condition for each well is an essential factor to determine the well status and to prevent a serious reservoir damage if there is a cross flow phenomena. Therefore, temperatures measurement at varies depths were used to establish the temperature profile which is reflecting the downhole condition. Several oil wells are subject to be evaluated through the campaigns in terms of downhole integrity especially casing leaks problems. Due to long period of shutdown for the field, close monitoring surveys with more focus on the aged wells are required to avoid flow behind pipe and cross flow phenomena, which will lead to the formation damage and production losses.
The applied approach which is related to Well Integrity Management (WIM) started by creating a baseline in terms of temperatures profile for each well at cost effective time-lapse. The reference is a geothermal gradient log recorded in shut-in condition. Slickline operations were performed to execute the bottomhole temperature surveys. The temperature profile interpretation added great value in terms of confirming the wellbore integrity and detecting anomalies such as a sustained casing pressure and casing leaks. Effectiveness Well Integrity Management (WIM) included the methodology of monitoring, detecting, and localizing leaks phenomena across shallow aquifers was used to extend the well operability life.
The approach was implemented on several field cases in order to detect casing leaks in offshore oil wells. A capture of temperature anomalies were found with a clear deviation from the baseline gradient. Based on the evaluation results, many of anomalies were related to the entry of fluids into the borehole. However, there were some cases indicated that the fluid flow was upward. It is noted that the temperature was affected by the type of occupied fluid into the outside casing and by the type of movements. As a result, the temperature profile was sensitive to not only the borehole condition but also the formation type and the casing-formation annulus.
The paper covered field wells completions evaluated and interpreted their temperature profiles to capture the temperatures anomalies leading to casing leak, flow behind pipe, and a cross flow phenomena. The approach applied further investigation by integrating technique with other integrity surveillance logs. In addition, the results from the workover operation with the remedial actions shared in order to validate the findings.
Combining Two- and Three-Phase Coreflooding Experiments for Reservoir Simulation Under WAG Practices
Authors: Moghadasi Leili , Ranaee Ehsan , Renna Dario , Bartosek Martin , Maddinelli Giuseppe , Masserano Franco , Cominelli Alberto , Inzoli Fabio , Guadagnini Alberto 
Published: January 2020

Enhanced oil recovery (EOR) processes may often involve simultaneous flow of two or three immiscible fluids inside the reservoir. A precise evaluation of relative permeabilities is critical to quantify multi-phase flow dynamics, assisting improved management and development of oil- and gas- bearing formations. This study illustrates the results of laboratory-scale investigations of multiphase flow on a sandstone reservoir core sample to evaluate relative permeabilities under two- and three-phase (i.e., water, oil, and gas) conditions. We use the ensuing information to simulate WAG injection at reservoir scale.The experiments are conducted at high temperature, consistent with reservoir conditions, to obtain two- (oil/water and oil/gas) and three-phase (oil/water/gas) relative permeabilities through Steady-State (SS) technique. Our laboratory workflow allows for an improved investigation by combining coreflooding experiments with in-situ X-Ray evaluation of local saturation distribution. The latter technique permits to asses slice-averaged phase saturation along the rock core, enabling to compute saturation profiles and average saturations while flooding, thus yielding significant advantages over traditional methodologies based on mass balance.Three-phase steady state (SS) experiments are performed by following diverse saturation paths, and the complete experimental dataset is provided to (a) assess the occurrence of local three-phase saturation conditions and (b) possibly investigate hysteretic effects of relative permeabilities. We evaluate three-phase relative permeabilities across the entire three-phase saturation region by leveraging a Sigmoid-based model (Ranaee et al., 2015).The resulting set of experimental two- and three-phase coreflooding results constitute a unique dataset which is then employed for reservoir simulation studies mimicking WAG injection and results are discussed in comparison with reservoir production under a waterflooding scenario.
Using the Product-Process Matrix to Identify Repeatability in Capital Project Activities to Improve Project Execution Efficiency
Authors: Shenoy Ramachandra 
Published: January 2020

Project teams in oil & gas major capital projects usually believe that large oil & gas capital projects typically have unique scope and are comprised of highly customized elements. We show that large capital oil & gas projects have a lot of inherent repeatability, using a well-known analysis from Operations Science of processes and products called the Product-Process Matrix. We use this observation to show Operations Science methods, specifically a technical framework known as Project Production Management (PPM), can be applied to the execution and delivery of all projects, large or small, customized or standardized, improving project performance over prior conventional project management practices.
We elaborate upon the Operations Science foundation underpinning the PPM framework, showing how it allows for a scientific analysis of the repeatability occurring in project work activities in different forms – knowledge, process and products. We start by identifying the assumptions of repeatable knowledge implicit in the disciplines used in conventional project management. We review the prior literature and taxonomy of a production system. All manufacturing systems are production systems. However, not all production systems are manufacturing systems. Manufacturing systems are but one type of production system. We explain that the belief that PPM is a simple application of line flow – also known as high volume manufacturing – is an overly simplistic characterization of PPM. A deeper analysis of the work activities of projects shows different types of production systems embedded within a typical project. Describing the work activities encountered in a project as a set of inter-connected production systems makes them amenable to the modeling and analysis tools of PPM, such as Little's Law and Kingman's Formula, which can be used to predict the limits of project execution and where best to manage variability by the strategic allocation of buffers such as capacity, inventory and time. We illustrate the concepts by identifying examples of repeatability present in an actual oil & gas capital projects.