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Results
Phase Behavior and Storage in Organic Shale Nanopores: Modeling of Multicomponent Hydrocarbons in Connected Pore Systems and Implications for Fluids-in-place Estimates in Shale Oil and Gas Reservoirs
Dhanapal, Kaverinathan (University of Oklahoma) | Devegowda, Deepak (University of Oklahoma) | Zhang, Yijia (University of Oklahoma) | Contreras-Nino, Adriana C. (University of Oklahoma) | Civan, Faruk (University of Oklahoma) | Sigal, Richard (University of Oklahoma)
Abstract Although there have been several efforts to quantify storage in shale nanopores, these have largely been based on generalization of the formulations for conventional reservoirs. Additionally, there is a lack of data addressing the effects of pore proximity on multicomponent adsorption and storage at a diverse set of pressures. Because it is nearly impossible with the currently available technologies to assess storage at the nano-scale, our work relies on the use of Molecular Dynamic simulation (to be called as MDS henceforth) techniques as well as a modified version of the Peng-Robinson EOS appropriate for modeling fluid behavior under pore proximity effects. We first describe the modified PR-EOS and demonstrate applications of pore confined methane phase behavior for different pore size distributions. For these chosen pore size distributions that are representative of organic nanopores, we derive an effective pore size that reproduces the composite phase behavior of the distribution of pore sizes. An effective pore size is defined because of the need to employ only one EOS for compositional modeling. Current efforts at modeling pore-confined phase behavior are largely restricted to tubes of a specified radius and may necessitate several fit-for-purpose EOS to model fluid behavior in different subsets of the pore size distribution. We demonstrate the need for careful examination of phase behavior when the pore volume contribution from the smallest of pores (sub-2nm) is substantial. However, our results indicate that for internmediate sized nanopores, an effective pore size representing the entire porous media may be derived. We then extend our modeling work to multicomponent systems and focus on the storage characteristics and phase behavior under confinement of a mixture of methane and octane. These results also indicate that when a substantial percentage of the pore volume is contained in the smallest of pores, the search for an effective pore size can become challenging. We then demonstrate some of the issues associated with fluid storage in organic nanopores by employing the graphene slit pore model. We model a replica of a connected pore system and demonstrate that pore proximity effects can substantially alter our expectations of storativity of methane, especially in the adsorbed layer. Finally, we demonstrate the need for moving beyond monolayer Langmuir adsorption models for describing storage by highlighting observations of multilayer adsorption of methane in organic pores. The key findings from this paper are as follows: Firstly, because the properties of alkanes differ with pore size, this study is the first to demonstrate that with complex pore connectivities, a simple extension of analyses from a single pore to connected pore systems is somewhat inadequate. This has implications for generating adsorption curves for reservoir simulation, to quantify fluids-in-place and to understand vapor-liquid equilibrium under the influence of pore proximity. We finally demonstrate that careful consideration of pore proximity effects in connected pore systems is necessary for a more meaningful quantification of reserves and predictions of well performance.
- North America > United States > Texas (0.46)
- North America > United States > Colorado (0.28)
Copyright 2013, Society of Petroleum Engineers This paper was prepared for presentation at the SPE Unconventional Resources Conference-Canada held in Calgary, Alberta, Canada, 5-7 November 2013. This paper was selected for presentation by an SPE program committee following review of information contained in an abstract submitted by the author(s). Contents of the paper have not been reviewed by the Society of Petroleum Engineers and are subject to correction by the author(s). The material does not necessarily reflect any position of the Society of Petroleum Engineers, its officers, or members. Electronic reproduction, distribution, or storage of any part of this paper without the written consent of the Society of Petroleum Engineers is prohibited. Permission to reproduce in print is restricted to an abstract of not more than 300 words; illustrations may not be copied. The abstract must contain conspicuous acknowledgment of SPE copyright. Abstract This paper primarly focuses on the proper description of single-and multi-component hydrocarbon transport in nanoporous organic-rich shales and therefore presents the relevant issues and exploratory modeling studies to account for the effects necessary for accurate reservoir simulation. The deviation from the Darcian flow behavior of the gas/condensate transport through shale reservoirs is shown to occur mainly by alteration of fluid properties because of pore proximity effects at elevated reservoir pressure and temperature conditions although the Knudsen and Klinkenberg type corrections may involve at low pressures at later stages of hydraulically-fractured wells in shale reservoirs. A systematic methodology is presented for modification of the fluid and phase behavior relevant to transport at elevated pressure and temperature conditions. The modifications of the phase diagram, density, viscosity, and surface tension for typical hydrocarbon components and mixtures in various size pores reduced further by adsorbed components layers are compared with those of the bulk systems. Further, the role of organic connectivity in shales characterized by organic and inorganic nanopores on production from shale wells is investigated.
- North America > United States > Texas (0.46)
- North America > Canada > Alberta > Census Division No. 6 > Calgary Metropolitan Region > Calgary (0.24)
Abstract The fluid properties modifications in nanoporous systems produced by the effect of pore wall potentials and the limited number of molecules in nanopores are investigated for liquid-rich shales. These properties include phase behavior, interfacial properties, gas and liquid transport, storage, and composition. The existing theoretical equations are modified to predict the vapor-liquid equilibrium for shale and the unique behavior of fluids in kerogen and inorganic pores. The pore geometry, molecule size, interaction between the sorbed molecules and the nanoporous framework are included to enable accurate prediction of fluid phase behavior, critical properties, and composition. The predictions of the proposed approaches are compared to results obtained using bulk fluid properties. The implications of ignoring the role of pore proximity on fluid properties can potentially be severe and can potentially compromise estimates of drainage areas, well spacing, recovery factors and reserves.
Critical Evaluation of Equations of State for Multicomponent Hydrocarbon Fluids in Organic Rich Shale Reservoirs
Zhang, Yijia ( University of Oklahoma) | Civan, Faruk (University of Oklahoma) | Devegowda, Deepak (University of Oklahoma) | Jamili, Ahmad (University of Oklahoma) | Sigal, Richard F. (Consultant)
Abstract The various equations of state and modifications proposed for use in nanoporous systems are critically examined. The fluid properties modifications in nanoporous systems produced by the effect of pore wall potentials and the limited number of molecules in nanopores are investigated for liquid-rich shale. These properties include phase behavior, interfacial properties, gas and liquid transport, storage, and composition. The existing theoretical equations are modified to predict the vapor-liquid equilibrium for shale and the unique behavior of fluids in kerogen and inorganic pores. The pore geometry, molecule size, interaction between the sorbed molecules and the nanoporous framework are included to enable accurate prediction of fluid phase behavior, critical properties, and composition. The predictions of the proposed approaches are compared to results obtained from molecular dynamic simulations. Introduction The study of fluid properties in nanoporous systems continues to receive considerable attention because of the shift towards the development of liquid-rich shale plays. In these nanoporous shales, it is now increasingly recognized that pore-wall proximity determines to a large extent the fluid phase behavior, its interfacial properties, gas and liquid transport, storage, and composition. We focus on a comprehensive and critical evaluation of existing equations-of-states (EOS) to quantify vapor-liquid equilibrium for shales and review the need for modified EOS's in order to address the unique behavior of fluids in kerogen and inorganic pores. Several factors that need to be considered are the pore geometry, molecule sizes, interaction between the sorbed molecules and the nanoporous framework. Proper consideration of these factors will enable more accurate prediction of fluid phase behavior, its critical properties, and composition which will lead to improved forecasting and reserves estimation. We review the limitations in the applicability of existing EOS for multicomponent, multiphase fluid description in shale nanopores. A comparison is made of the predictive capability of these equations against results obtained from pore scale molecular dynamic simulations describing fluid phase behavior in nanopores. We then review the modifications to these equations of states proposed to capture pore wall proximity effects and explore the validity of these for compositional shale gas simulation. Finally, we propose convenient modifications to existing EOS that quantifies fluid phase and compositional behavior across a wide range of pore sizes and pore pressures in adsorbing and non-adsorbing walls. The approach to modification of equations-of-state outlined in our work enables improved reservoir performance forecasting, reserves estimation, calculations of condensate dropout and additionally, enables operators to characterize the original in-situ fluid composition from the produced gas and liquid streams. URTeC 1581765
A Pore Scale Study of Slickwater Systems in Shale Reservoirs: Implications for Frac-Water Distribution and Produced Water Salinity
Hu, Yinan (University of Oklahoma) | Devegowda, Deepak (University of Oklahoma) | Striolo, Alberto (University of Oklahoma) | Phan, Anh (University of Oklahoma) | Ho, Tuan A. (University of Oklahoma) | Civan, Faruk (University of Oklahoma) | Sigal, Richard (Consultant )
Abstract Pore-level molecular dynamics simulation studies are conducted towards an understanding of poor recovery of frac-water, progressive increase in produced water salinity, and identification of potential trapping mechanisms for frac-water and its influence on long-term well productivity in shale gas and oil reservoirs. The kerogen pores of shales are represented by two organic pore models. The first model containing only carbon is intended to mimic the nature of highly mature kerogen. The second model helps understanding of the fluid behavior in partially mature shales containining oxygenated functional groups with non-zero oxygen to carbon ratio. The maturation processes of these kerogen models are described by means of a molecular dynamics simulation. These models are shown to describe effectively the essential structural features observed in SEM images which indicate surface roughness, tortuous paths, material disorders, and imperfect pore openings of kerogen pores, and are therefore superior to the frequently assumed graphene slit pore systems. The effect of maturation, pore surface mineralogy, and pore roughness on the wettability characteristics of organic kerogen pores is delineated. Distribution of saline water in organic and inorganic pores is described as a function of pore size and morphology. These pore-scale studies reveal important insights about the distribution of dissolved ions and water in organic pores, and the frac-water distribution and produced water salinity following hydraulic fracturing. Introduction Shale gas and oil development activities have continually undergone several stages of refinement and continues to be driven by our ability to create extensive multi-stage hydraulic fracture treatments along several thousands of feet of horizontal laterals. Although these efforts have largely progressed successfully, unfortunately, our current understanding of the complex interplay of hydrocarbons and water in organic and inorganic shale nanopores is rather limited. Among the key questions remaining unanswered are related to the explanation of the poor recovery of frac-water, the progressive increase in produced water salinity, and the potential trapping mechanisms for frac-water and its influence on long-term well productivity. URTeC 1579803
- North America > United States > Texas (0.68)
- North America > United States > Oklahoma > Cleveland County > Norman (0.15)
- Geology > Rock Type > Sedimentary Rock > Clastic Rock > Mudrock > Shale (1.00)
- Geology > Petroleum Play Type (1.00)
- North America > United States > Texas > West Gulf Coast Tertiary Basin > Eagle Ford Shale Formation (0.99)
- North America > United States > Texas > Sabinas - Rio Grande Basin > Eagle Ford Shale Formation (0.99)
- North America > United States > Texas > Maverick Basin > Eagle Ford Shale Formation (0.99)
- (11 more...)
- Well Completion > Hydraulic Fracturing (1.00)
- Reservoir Description and Dynamics > Unconventional and Complex Reservoirs > Shale oil (1.00)
- Reservoir Description and Dynamics > Unconventional and Complex Reservoirs > Shale gas (1.00)
- Health, Safety, Environment & Sustainability > Environment > Water use, produced water discharge and disposal (1.00)
A Pore Scale Study Describing the Dynamics of Slickwater Distribution in Shale Gas Formations Following Hydraulic Fracturing
Hu, Yinan (University of Oklahoma) | Devegowda, Deepak (University of Oklahoma) | Striolo, Alberto (University of Oklahoma) | Ho, Tuan A. (University of Oklahoma) | Phan, Anh (University of Oklahoma) | Civan, Faruk (University of Oklahoma) | Sigal, Richard (University of Oklahoma)
Copyright 2013, Society of Petroleum Engineers This paper was prepared for presentation at the Unconventional Resources Conference-USA held in The Woodlands, Texas, USA, 10-12 April 2013. This paper was selected for presentation by an SPE program committee following review of information contained in an abstract submitted by the author(s). Contents of the paper have not been reviewed by the Society of Petroleum Engineers and are subject to correction by the author(s). The material does not necessarily reflect any position of the Society of Petroleum Engineers, its officers, or members. Electronic reproduction, distribution, or storage of any part of this paper without the written consent of the Society of Petroleum Engineers is prohibited. Permission to reproduce in print is restricted to an abstract of not more than 300 words; illustrations may not be copied. The abstract must contain conspicuous acknowledgment of SPE copyright. Abstract Hydraulic fracturing with slickwater to stimulate shale gas wells is routinely employed to enable increased contact with larger reservoir volumes and has the advantages of lower cost, the ability to create larger and more complex fractures, less formation damage and easier cleanup. However, a common observation is that during flow back only 10 to 20% of the frac water is recovered, even though a typical stimulation job requires several million gallons of water. Although there have been some attempts to address this phenomenon, the associated theories are lacking in scientific rigor. Due to the nanoporous nature of shales where pore proximity effects and strong inter-molecular interactions may dominate, a fundamental pore-level analysis is employed in this work to better understand and leverage the dynamics of the physiochemical processes during and after fracturing. By varying pore size in organic and inorganic pores in shales, we study the dynamics of water and gas molecules, as well as that of ions.
Phase Behavior of Gas Condensates in Shales Due to Pore Proximity Effects: Implications for Transport, Reserves and Well Productivity
Devegowda, Deepak (University of Oklahoma) | Sapmanee, Kanin (University of Oklahoma) | Civan, Faruk (University of Oklahoma) | Sigal, Richard (University of Oklahoma)
Abstract The present study investigates the alteration of the properties, transport, and production of gas-condensates in shale gas reservoirs and develops and demonstrates an effective and practical methodology to apply these modifications in existing numerical simulation software. Simple models that investigate the phenomena can be investigated without the need for any modifications to an existing simulation code, but realistic models will require significant modifications. Our modeling results indicate that when pore sizes are in the sub-10 nm range, typical of many gas shales, the influence of pore walls on the phase behavior and viscosity of typical gas-condensate fluids is dramatic, in both organic and inorganic pores, and creates favorable fluid and transport conditions leading to enhanced production. This is because the fluid mixture in such porous formations tends to exhibit behavior similar to that of a dry gas or a leaner gas-condensate system, thereby reducing the condensate banking effect considerably in the near-wellbore region and consequently, not impairing the productivity of the producing well. The results also underscore possible reasons for the significant production of condensate liquid from these nanoporous media in contrast to what is expected based on the industry's collective experience with conventional reservoirs. Consequently, the analysis and exercises carried out in this article provide valuable insights into the nature of fluid behavior and advances our understanding of the mechanisms of gas-condensate transport in extremely low permeability nanoporous media.
- Africa (0.67)
- North America > United States > Texas (0.46)
- North America > United States > Texas > West Gulf Coast Tertiary Basin > Eagle Ford Shale Formation (0.99)
- North America > United States > Texas > Sabinas - Rio Grande Basin > Eagle Ford Shale Formation (0.99)
- North America > United States > Texas > Maverick Basin > Eagle Ford Shale Formation (0.99)
- (2 more...)
- Reservoir Description and Dynamics > Unconventional and Complex Reservoirs > Shale gas (1.00)
- Reservoir Description and Dynamics > Unconventional and Complex Reservoirs > Gas-condensate reservoirs (1.00)
- Reservoir Description and Dynamics > Fluid Characterization > Phase behavior and PVT measurements (1.00)