Agenda | All Times Central European Time (UTC +1)
Tuesday, March 23
Erling Halfdan Stenby
Technical University of Denmark
Reservoir fluid characterisation for reservoir and production system modelling is dependent on obtaining representative fluid property measurements of all reservoir fluids (oil, gas, water) at reservoir conditions. These fluid property measurements can either be made directly with downhole tools (downhole fluid analysis) or by collecting samples that are then sent to a laboratory for detailed characterisation. In this session, we discuss the various methods and recent technology advancements for bottom hole sampling during drilling, logging, and well testing operations with goal of obtaining representative hydrocarbon and water samples for laboratory analysis. In addition, we look at methods and techniques used for the measurement of fluid properties downhole and the value of these measurements in well fluid characterisation optimisation.
Experimental PVT study is the basis for understanding and modeling reservoir fluids. Standard PVT measurements can handle most routine requests for fluid phase behavior but there is an increasing need for advanced PVT measurements customised for challenging fluids like near-critical fluids or heavy oils, for extreme conditions like HPHT, and for special properties like diffusion coefficients or MMPs. Meanwhile, new measurement techniques emerge as solutions to these experimental challenges, or as alternatives with better accuracy, higher efficiency, or smaller sample amounts. This session is dedicated to the recent developments of novel experimental techniques. We will discuss how the new developments contribute to the measurement of challenging fluid systems or the improvement of the measurement accuracy or efficiency. We will also discuss the gap between the industrial needs and the existing techniques.
Production from tight formations like shale in the US and lower cretaceous in the North Sea no doubt present special challenges. That goes for both the practical production and simulation of the production. Are these challenges due to the tightness of the formation, or are the fluids from these resources fundamentally different from fluids from conventional resources? In other words, if a fluid from an unconventional resource is taken to the lab, does it then behave in a special way, is the chemical fingerprint different in some significant way, or do other differences of interest exist? As an example it seems like fluids from shale are quite paraffinic. Does that hold for all shale fluids and does it for instance mean that they never present an asphaltene problem?
Another aspect of PVT is which PVT properties are of importance. As an example in a gas injection EOR scenario in a conventional resource, swelling of the fluid with injection gas and the critical transition from oil type fluid to gas condensate type fluid make up important data points. EOR from unconventional resources may involve huff-n-puff rather than continuous gas injection, and molecular diffusion rates may be important for the success of the method. Does the above mean that another measurement campaign is required compared with conventional resources to assess the behaviour of the fluids and the reservoir during production, and does the same apply even if only primary depletion is considered? Is there another set of requirements for accuracy of measurement or modelling of PVT in the context of unconventional resources?
This session invites contribution around the above topics with focus on the PVT aspect. Results from reservoir simulations etc. can be included to support the statements made. Worked examples are encouraged over purely theoretical considerations.
The aspects of estimating the original fluid in place and assigning the proper variation of fluids for reservoir initialisation are important but are not main topics in this session. Contributions on those subjects may be referred to other sessions.
In complex fluid systems, to predict properly reservoir fluid properties, geological and geochemical parameters has to be integrated. Complex charges history, including deep fluid, or fluid secondary modification is a key knowledge to better assess vertical gradients, potential gas oil contact and connectivity, leading to reservoir fluid properties variability. Over the last decade, new geochemical tracers – like quantitative analysis and isotopy of mud gases, multi-isotopic approach or noble gases – were developed to better assess physical parameters (kinetic and thermodynamic) affecting reservoir fluid and thus giving supplementary constrains to predict fluid properties over the field.
Wednesday, March 24
Understanding fluid composition variations within a hydrocarbon accumulation based on a limited number of sample points is challenging. Gravity and geothermal gradients are some of the processes that can induce large compositional variations within the fluid column. Compartmentalisation can also lead to different fluid compositions being observed. To rationalise and understand the fluid distribution in such systems, different types of data and different modeling approaches are required. For example, models that use irreversible thermodynamics open the door for developing simple predictive tools. Combined with connectivity studies through natural tracers analysis and interpretation tools can help build the full picture of reservoir fluid spatial distribution. These technologies still need further development. In the session, such new modeling applications and approaches to data acquisition and analysis will be discussed, along with relevant field examples
Reservoir fluids containing sour components (CO2 / H2S / mercaptans / elemental sulfur, etc.) exist in many reservoirs throughout the world. The interest in sour gas injection for EOR and CO2 capture / sequestration is also growing. This session is designed to stimulate the discussion on wide-ranging topics related to sour reservoir fluids and carbon capture / storage. The relevant topics in this session include, but are not limited to, the subsurface variation of sour components in reservoir fluids; processing of sour reservoir gases; phase behavior and fluid properties of sour reservoir fluids and their interacting with brine related to sour reservoir fluids production, sour gas injection for EOR and carbon sequestration mechanisms. The discussion of this session will be focused on the state of art for experimental investigation / measurement, numerical modeling as well as field examples / pilot cases related to those topics.
In line with industry 4.0 revolution, transformational digital technologies (TDT) will be making dramatic changes in addressing the oil and gas industry technical challenges. Fluids will be a critical part of these challenges whether flow by themselves or interact with rocks at the interfaces. This session intends to cover current practical TDT application on addressing: (a) complex fluid phase equilibria and phase properties, (b) complex rock/fluid interaction, and (c) complex transport through porous media. Theoretical and modelling/simulation with practical examples will be presented to inspire more innovations to further advance the complex reservoir fluid technologies.
Modern project development, particularly in complex and expensive environments, relies on integrated field development concepts. This requires consistent fluid properties in all parts of the integrated model from reservoir to export pipeline. Commonly, a multi-fidelity approach is taken where level of modelling detail is adapted to the business problem at hand, e.g., bulk phase behaviour and fluid properties in a black oil reservoir; thermal effects in wells and networks; and detailed compositional accounting in facilities and plants. Similarly, modelling and mitigation of fluid risks such as flow assurance requires additional sophistication in pipe flow that may not be warranted or too computationally expensive in discretized reservoir models. This session will discuss best practices for holistic/consistent treatment of fluids throughout the modelling scope, as well as novel approaches and strategies to mitigate and control inevitable errors and inconsistencie
Thursday, March 25
Session 9 is designed to explore the applications and challenges of appropriate characterisation/representation of complex fluids in EOR processes. The current efforts in the industry expanding gas EOR into deeper (Deepwater) and tighter (unconventional) formations have identified the needs of reliable measurements and representation of the fluid properties and phase behavior at extra-high reservoir pressures or in extremely-tight pore spaces. The simulation of such processes requires compositional formulations and robust representation of the reservoir heterogeneity, especially highly-fractured reservoirs (both conventional and unconventional). In this session we will discuss the latest findings in the industry from laboratory data collection to effective formulations of gas EOR simulation.
Flow assurance issues include organic and inorganic deposition and emulsion formation in the reservoir, wellbore, pipeline, and surface facilities. This session focuses on recent work on the source of flow assurance problems including asphaltene and wax precipitation, emulsion stability, and inorganic scale formation during reservoir production. We especially aim at discussions on topics where reservoir conditions and fluid chemistry leads to subsurface blockage and production reduction and how to forecast, mitigate and resolve these in novel ways.