Taha, Taha (Emerson Automation Solutions) | Ward, Paul (Emerson Automation Solutions) | Peacock, Gavin (Emerson Automation Solutions) | Heritage, John (Emerson Automation Solutions) | Bordas, Rafel (Emerson Automation Solutions) | Aslam, Usman (Emerson Automation Solutions) | Walsh, Steve (Emerson Automation Solutions) | Hammersley, Richard (Emerson Automation Solutions) | Gringarten, Emmanuel (Emerson Automation Solutions)
This paper presents a case study in 4D seismic history matching using an automated, ensemble-based workflow that tightly integrates the static and dynamic domains. Subsurface uncertainties, captured at every stage of the interpretative and modelling process, are used as inputs within a repeatable workflow. By adjusting these inputs, an ensemble of models is created, and their likelihoods constrained by observations within an iterative loop. The result is multiple realizations of calibrated models that are consistent with the underlying geology, the observed production data, the seismic signature of the reservoir and its fluids. It is effectively a digital twin of the reservoir with an improved predictive ability that provides a realistic assessment of uncertainty associated with production forecasts.
The example used in this study is a synthetic 3D model mimicking a real North Sea field. Data assimilation is conducted using an Ensemble Smoother with multiple data assimilations (ES-MDA). This paper has a significant focus on seismic data, with the corresponding result vector generated via a petro-elastic model. 4D seismic data proves to be a key additional source of measurement data with a unique volumetric distribution creating a coherent predictive model. This allows recovery of the underlying geological features and more accurately models the uncertainty in predicted production than was possible by matching production data alone.
A significant advantage of this approach is the ability to utilize simultaneously multiple types of measurement data including production, RFT, PLT and 4D seismic. Newly acquired observations can be rapidly accommodated which is often critical as the value of most interventions is reduced by delay.
Data from seismic to production is integrated to build models to provide estimations of parameters such as petroleum volumetrics, pressure behavior, and production performance (
Reservoir dynamic simulation is the most applied process that integrates all reservoir data, where an Equation of State (EOS) is coupled with the objective to estimate the fluid thermodynamic state at each computational step. The simulation consists of iterative mathematical computations in which the reservoir-defined conditions at the previous time step is an input to determine the properties at the next and subsequent time steps. The calculated pressure is a fundamental variable in each time step, which means that a representative and high level of confidence Pressure Volume Temperature (PVT) model is required to avoid scale-up of errors resulting from fluid pressure estimation.
A PVT modeling includes three main stages: Fluid sample and data acquisition Laboratory analysis and fluid characterization The EOS model.
Fluid sample and data acquisition
Laboratory analysis and fluid characterization
The EOS model.
The emphasis in this work is on the EOS model, which is the fluid model used for the simulation process. The objective of this work is to analyze the main uncertainties associated with typical EOS modeling and defining the level of confidence of these EOS approaches. In this work, some of the most-used approaches for EOS modeling are reviewed. An assessment of these methods is also provided based on their application to actual petroleum fluids with the objective of defining their statistical level of confidence.
First, the study analyzes the sources of critical uncertainties in a PVT EOS model. Second, a statistical number of PVT laboratory studies of petroleum fluids is used to determine the level of confidence of four approaches that are based on the two well-known Peng-Robinson and Soave-Redlich-Kwong EOS. Third, statistical analysis is performed to determine the level of confidence of the different methods. Fourth, a correlation to determine the optimal number of pseudo-components is defined. These steps include: Characterization of fluid and heavy components Tuning Lumping.
Characterization of fluid and heavy components
As a result of this study, one can conclude: The level of confidence of the four analyzed approaches The significance of the difference between the analyzed methods A correlation to determine the optimal number of pseudo-components.
The level of confidence of the four analyzed approaches
The significance of the difference between the analyzed methods
A correlation to determine the optimal number of pseudo-components.
In this work, a statistical analysis over some of the most-used EOS modeling approaches and on a set of petroleum fluid PVTs was performed to determine the level of confidence of four EOS modeling methods. In addition, a correlation was introduced for
Hjeij, Dawood (Division of Sustainable Development, College of Science and Engineering, Hamad Bin Khalifa University) | Abushaikha, Ahmad (Division of Sustainable Development, College of Science and Engineering, Hamad Bin Khalifa University)
Most commercially available simulators use the trivial two-point flux approximation (TPFA) method for flux computation. However, the TPFA only gives consistent solutions when used for K-orthogonal grids. In general, multi-point flux approximation (MPFA) methods perform better under both heterogeneous and anisotropic conditions. The mimetic finite difference (MFD) method is designed to preserve properties on unstructured polyhedral grids, and its development for simulating full tensor permeabilities is also crucial step. This paper compares the performance, accuracy, and efficiency of these schemes for simulating complex synthetic and realistic hydrocarbon reservoirs.
The Vega subsea field in Norway has been producing successfully using a continuous Mono Ethylene Glycol (MEG) injection, topped up with corrosion inhibition means. A topside reclamation process allows reuse of MEG, however, limits the possibilities to produce saline water. In order to manage wells producing saline formation water and to increase ultimate recovery, a new flow assurance and integrity philosophy without continuous MEG injection is considered. This paper describes the options on hydrate as well as integrity management and the modifications both on the subsea and topside facilities required to enable an operational philosophy change. This change of the operational philosophy appears feasible, using either timely depressurization or Low Dosage Hydrate Inhibitors (LDHI) as well as a film building corrosion inhibitor in the system.
As a result of the 2016 Paris agreement, the challenge of climate change and the imperative of moving to a low carbon economy has intensified. This challenge has been added to the traditional objectives of affordable and secure energy sources. These three criteria are the basis for the Energy Transition. Increasingly, investors, consumers and policy makers are looking to energy businesses to reflect all these criteria as the basis of their company culture and objectives.
This paper looks to explore opportunities for the UK oil and gas industry to further align itself with the drivers set out above and continue to promote investment into a sector that is key to delivering the Energy Transition:
Improved communication of carbon reduction and mitigation efforts at both a national and global level Increased collaborative efforts aimed at reducing emissions resulting from exploration and production offshore The potential for UKCS oil & gas companies’ involvement in carbon mitigation and storage
Improved communication of carbon reduction and mitigation efforts at both a national and global level
Increased collaborative efforts aimed at reducing emissions resulting from exploration and production offshore
The potential for UKCS oil & gas companies’ involvement in carbon mitigation and storage
Over recent years, the offshore UKCS oil and gas sector has focused on improving cost efficiency in its offshore operations. This implies a commitment to continuously improve environmental performance despite the challenges of doing so in a maturing oil and gas basin, where maximising economic recovery from fields requires greater effort. Notwithstanding these challenges, the overall long-term trends in environmental performance are improving as a result of efforts by the industry.
Moving forwards, the benefits of effective emissions management will continue to intensify, beyond the regulatory requirements of environmental protection, as a result of two key drivers:
To maintain investor and public confidence – reducing both the carbon footprint of operations and carbon intensity of products used by consumers, will help position companies for a lower carbon economy. The business case - EU ETS Phase IV is modelled to cost the sector £2.2 billion from 2021 to 2030 as the cost of allowances is projected to increase combined with the reduction in free allowances. Therefore, reducing emissions at installations will continue to be imperative for improved environment performance as well as the continued economic viability of the installation.
To maintain investor and public confidence – reducing both the carbon footprint of operations and carbon intensity of products used by consumers, will help position companies for a lower carbon economy.
The business case - EU ETS Phase IV is modelled to cost the sector £2.2 billion from 2021 to 2030 as the cost of allowances is projected to increase combined with the reduction in free allowances. Therefore, reducing emissions at installations will continue to be imperative for improved environment performance as well as the continued economic viability of the installation.
The sector must therefore continue to adapt to these ongoing fundamental changes that are taking place in energy supply more widely. As with any industry, businesses need to respond to shifting economic and societal demands and the consequent changes in energy needs. Hence, the effective management of emissions must proliferate through both operations (exploration, production and transportation of hydrocarbons), and use of the products delivered.
Digital technologies serve as a primary theme of this year’s group, with a few environmentally conscious firms included in the mix. The well will immediately be brought on production and is expected to flow at more than 100 MMscf/D of gas and 3,000 B/D of associated condensate, the company said. The main goal of production logging is to evaluate the well or reservoir performance. The shale sector is studying the results of a 23-well experiment in the southeastern corner of New Mexico to learn what the wider implications might be. The shale sector is making moves to consolidate amid investor pressure to increase cash flow.
A challenging problem of automated history-matching work flows is ensuring that, after applying updates to previous models, the resulting history-matched models remain consistent geologically. To enhance the applicability of localization to various history-matching problems, the authors adopt an adaptive localization scheme that exploits the correlations between model variables and observations. This paper presents a novel approach to generate approximate conditional realizations using the distributed Gauss-Newton (DGN) method together with a multiple local Gaussian approximation technique. This work presents a systematic and rigorous approach of reservoir decomposition combined with the ensemble Kalman smoother to overcome the complexity and computational burden associated with history matching field-scale reservoirs in the Middle East. This paper presents a comparison of existing work flows and introduces a practically driven approach, referred to as “drill and learn,” using elements and concepts from existing work flows to quantify the value of learning (VOL).
Are fugitive releases of natural gas and flaring environmental concerns? Can these be ameliorated today and even better in the future? What Is All This Talk About Emissions? Emissions are in the air and in the headlines every day. With growing regulations around all types of air emissions, are there ways that industry can deploy technologies cost-effectively in the current environment?
From the highest courts of the US judicial branch to the C-suite, contests involving patents have recently come to the fore in the innovation hungry US oilfield services industry, even as filings and litigation have declined in recent years. Seeking out, experimenting with, and ultimately embracing technologies from other industries have proven crucial to innovating at oilfield service firms such as Halliburton, which has tried everything from dog food to submarine tech to improve its work downhole. R&D may be the key to the survival of companies as the new economics of the industry take hold. The R&D Technical Section dinner at ATCE drew varying perspectives as the panelists discussed, and sometimes debated, a range of approaches to safeguarding industry viability and growth in the years ahead. Even as the oil and gas industry looks for the next great idea to propel it forward, it should constantly reconsider past innovations for inspiration, the CEO of a major operator said Monday on the opening day of 2017 SPE ATCE.
In need of an exploration boost, Norway doled out a record 83 production licenses in mature areas of the Norwegian Continental Shelf to 33 firms. Norway hopes for a continued rise in offshore exploration and development activity to ensure steady oil and gas production through the next decade. Equinor has grabbed seven new licenses in the Barents and Norwegian Seas, the latest in a flurry of offshore activity in which the firm has added acreage off the UK and Brazil, gained approval for a big Arctic project, and awarded billions of dollars in service contracts. A reservoir-conditions coreflood study was undertaken to assist with design of drilling and completion fluids for a Norwegian field. Multiple fluids were tested, and the lowest permeability alterations did not correlate with the lowest drilling-fluid-filtrate-loss volumes.