The Experts below are selected from a list of 21567 Experts worldwide ranked by ideXlab platform
Wanfen Pu - One of the best experts on this subject based on the ideXlab platform.
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low temperature oxidation and characterization of heavy oil via thermal analysis
Energy & Fuels, 2015Co-Authors: Wanfen Pu, Chengdong Yuan, Lei Wang, Zhen Qian, Yibo Li, Dong Li, Yafei ChenAbstract:High pressure air injection (HPAI) without ignition has attracted extensive attention in the air injection based improved oil recovery (IOR) process for light oil Reservoirs but was rarely proposed as an IOR process for heavy oil Reservoirs. This study aims at evaluating the potential of HPAI without ignition for deep, high pressure, heavy oil Reservoirs (Tahe oilfield, Tarim Basin, China). Many low-temperature oxidation (LTO) experiments were carried out to study the oxidation behavior of heavy oil under the Reservoir conditions (120 °C, about 30–40 MPa) using an isothermal oxidation reactor. The produced gases were analyzed using gas chromatography for their content of O2, CO2, CO, and hydrocarbon gas (C1–C6) content. The apparent hydrogen/carbon (H/C) and molar ratio of the carbon oxides (m-ratio) were also calculated from effluent gases to analyze oxidation behavior. The effects of quartz, Reservoir Core (characterized by X-ray diffraction), formation water, and catalyst on LTO were analyzed. Thermogr...
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thermal study on light crude oil for application of high pressure air injection hpai process by tg dtg and dta tests
Energy & Fuels, 2012Co-Authors: Jinzhou Zhao, Wanfen Pu, Ji Zhao, Xiyu KuangAbstract:High-pressure air injection (HPAI) in light oil Reservoirs has proven to be a valuable improved oil recovery (IOR) process and aroused more attention worldwide. In this research, laboratory experiments were performed to study the potential of HPAI application in Keke Ya oilfield (Tarim Basin, China). Test oil and actual Reservoir Core samples were taken from Keke Ya oilfield, and rock composition was prior analyzed through X-ray method. The thermal behaviors of oil-only, cuttings, and oil-cuttings were studied by thermogravimetry/derivative thermogravimetry (TG/DTG), differential thermal analysis (DTA) tests, and also, rock composition and clay mineral type/relative content effects on light crude oil oxidation behavior were systematically investigated. The results show that Keke Ya oil has a favorable exothermic behavior, exhibiting apparent low-temperature oxidation (LTO), fuel deposition, and high-temperature oxidation (HTO) stages. An extended fuel deposition stage was observed by addition of cuttings....
Yafei Chen - One of the best experts on this subject based on the ideXlab platform.
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low temperature oxidation and characterization of heavy oil via thermal analysis
Energy & Fuels, 2015Co-Authors: Wanfen Pu, Chengdong Yuan, Lei Wang, Zhen Qian, Yibo Li, Dong Li, Yafei ChenAbstract:High pressure air injection (HPAI) without ignition has attracted extensive attention in the air injection based improved oil recovery (IOR) process for light oil Reservoirs but was rarely proposed as an IOR process for heavy oil Reservoirs. This study aims at evaluating the potential of HPAI without ignition for deep, high pressure, heavy oil Reservoirs (Tahe oilfield, Tarim Basin, China). Many low-temperature oxidation (LTO) experiments were carried out to study the oxidation behavior of heavy oil under the Reservoir conditions (120 °C, about 30–40 MPa) using an isothermal oxidation reactor. The produced gases were analyzed using gas chromatography for their content of O2, CO2, CO, and hydrocarbon gas (C1–C6) content. The apparent hydrogen/carbon (H/C) and molar ratio of the carbon oxides (m-ratio) were also calculated from effluent gases to analyze oxidation behavior. The effects of quartz, Reservoir Core (characterized by X-ray diffraction), formation water, and catalyst on LTO were analyzed. Thermogr...
Christoph H Arns - One of the best experts on this subject based on the ideXlab platform.
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mapping 3d pore scale fluid distributions how rock resistivity is influenced by wettability and saturation history
Petrophysics, 2010Co-Authors: Munish Kumar, Mark A Knackstedt, Shane Latham, Adrian Sheppard, Trond Varslot, Timothy Senden, Robert Sok, Christoph H ArnsAbstract:Complexities in pore scale structure, rock-fluid and fluid-fluid interactions have a profound effect on the estimation of reserves, recovery and productivity in Reservoir rocks. These complexities determine the pore scale distribution of fluids within the pore space. An example is the estimation of water saturation via resistivity measurements. Default saturation exponents (n=2) are often used in estimating saturations despite experimental laboratory results which show a wide range; 0.9
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digital rock physics 3d imaging of Core material and correlations to acoustic and flow properties
Geophysics, 2009Co-Authors: Mark A Knackstedt, Shane Latham, Mahyar Madadi, Adrian Sheppard, Trond Varslot, Christoph H ArnsAbstract:3D X-ray microtomographic imaging and visualization of Core material at the pore scale and subsequent analysis of petrophysical properties can give important insight to understanding properties of Reservoir Core material. 3D images allow one to map in detail the pore and grain structure and interconnectivity of Core material. Numerical calculations on image data are in agreement with experimental data for flow and elastic properties on simple Core material. This development forms the basis for developing more meaningful structure-property correlations in rock.
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Mapping Fluid Distributions In 3D At The Pore Scale: Quantifying The Influence Of Wettability And Saturation History On Rock Resistivity
2009Co-Authors: Munish Kumar, Mark A Knackstedt, Shane Latham, Adrian Sheppard, Trond Varslot, Timothy Senden, Robert Sok, Christoph H ArnsAbstract:Complexities in pore scale structure, rock-fluid and fluid-fluid interactions have a profound effect on the estimation of reserves, Reservoir recovery and productivity in Reservoir Core material. These complexities determine the pore scale distribution of fluids within the pore space, which, in turn, determine the petrophysical response of the rock. A very important example is the estimation of water saturation via resistivity measurements. Default saturation exponents (n=2) are often used in estimating saturations despite numerous measurements which have shown that n can depend strongly on the rock type, mineralogy, saturation history and wettability. NonArchie behavior is reported frequently. Experimental laboratory results for the resistivity response of clastic and carbonate Reservoir Cores under varying wettability states have exhibited a range of saturation exponents; 1
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3D Imaging of Reservoir Core at Multiple Scales; Correlations to Petrophysical Properties and Pore Scale Fluid Distributions
All Days, 2008Co-Authors: Abid Ghous, Mark A Knackstedt, Shane Latham, Adrian Sheppard, Christoph H Arns, Timothy Senden, Robert Sok, Munish Kumar, Anthony C. Jones, Holger AverdunkAbstract:Abstract The prediction of hydrocarbon recovery is related to both the detailed pore scale structure of Core material and fluid interfacial properties. An increased understanding of displacement efficiencies and overall recoveries requires an ability to characterize the pore structure of Reservoir Core in 3D and to observe fluid distributions at the pore scale. Micro-CT imaging is capable of acquiring 3D images of the pore structure of sedimentary rock with resolutions down to the micron scale. This allows the 3D pore-space of many Reservoir rock samples to be imaged at the pore scale. The 3D porespace of tighter clastics and carbonate Core material includes a significant proportion of microporosity—pores at the submicron scale which are not directly accessible via current micro-CT capabilities. Porosity at all scales can affect fluid flow, production, recovery data and log responses. It is important to characterize pore structure and connectivity in a continuous range across over six decades of length scales (from nm to cm) to better understand these petrophysical and production properties. In this paper we describe 2D and 3D imaging studies of Reservoir Core via micro-CT coupled with complementary petrographic techniques (thin section, mercury intrusion) and high resolution focused ion beam (FIB) scanning electron microscopy studies of a range of Reservoir Core. Results are given which illustrate the importance of pore structures at varying scales in determining petrophysical properties. Microtomography is then used to observe pore scale fluid distributions within the Core material. Displacement experiments under controlled wettability conditions are undertaken. The local pore-scale fluid distributions identified via 3D tomographic imaging experiments. These results provide insight into the role of rock microstructure in determining recovery and production characteristics. Introduction Micro-CT (µ-CT) imaging [1,2] is becoming increasingly popular for characterising many macroscopic properties of porous media. From µ-CT images one is able to compute petrophysical properties such as porosity, permeability, conductivity, elasticity, and mercury injection capillary pressure (MICP). Rock properties derived from fragments of a range of Cores including homogeneous and Reservoir sands have been compared with conventional laboratory measurements and shown to be in good agreement [3,4]. In more complex Cores (e.g., carbonates, heterogeneous sands, tight gas) one must consider the role of pore structure in a continuous range across over many decades of length scales (from nm to cm) to better understand these processes. For example, in carbonate rocks, the processes of sedimentation and diagenesis produce a complex spatial distribution of pores and pore connectivity across several decades of length scales. Therefore developing a reliable petrophysical interpretation for predicting the transport properties and producibility of complex Cores such as carbonates remains difficult. In this paper we describe 2D and 3D imaging studies of complex Reservoir Core material via µ-CT coupled with complementary petrographic techniques (thin section, SEM) and high resolution focused ion beam tomography (FIBT). We utilize a newly developed image registration technique for aligning high-resolution 2D microscopy (SEM, Optical) images of Core thin sections with the corresponding region of the micro-CT 3D image of the Core. The integration of aligned high resolution (nm scale) data with 3D µ-?CT data has the potential to increase the accuracy of the physical properties predicted from the 3D µ-CT image analysis.
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digital Core laboratory petrophysical analysis from 3d imaging of Reservoir Core fragments
Petrophysics, 2005Co-Authors: Abid Ghous, Mark A Knackstedt, Adrian Sheppard, Christoph H Arns, Arthur Sakellariou, Timothy Senden, Robert Sok, Wolf Val Pinczewski, Fabrice Bauget, John KellyAbstract:Machined fragments of a number of Core plugs have been analyzed using a high resolution X-ray micro-computed tomography (micro-CT) facility. The facility includes a system capable of acquiring 3D images made up of 2000 3 voxels on Core plugs up to 6 cm in diameter with resolutions down to 2 μm. The Cores analyzed include a range of plug fragments from two Reservoir sands. The Cores exhibit a range of pore and grain sizes, porosity and permeability. Computational results made directly on the digitized tomographic images are presented for permeability, formation factor, resistivity index and drainage capillary pressure across a range of porosity. We show that data over a range of porosity can be computed from a single fragment. Where available, we compare the computations of petrophysical data on fragments to conventional laboratory measurements on the full plug. Permeability predictions from digital and conventional Core analysis are consistent. It is shown that a characteristic length scale can be defined as a quality-control parameter for the estimation of permeability. Results for formation factor, drainage capillary pressure and resistivity index are encouraging. The results demonstrate a potential to predict petrophysical properties from Core material not suited to laboratory testing (e.g., sidewall or damaged Core and drill cuttings) and the feasibility of combining digitized images with numerical calculations to predict properties and derive correlations for specific rock lithologies. The small sample size required for analysis makes it possible to produce multiple measurements on a single plug. This represents a potential multiplier on the quantity of Core data allowing distributions of petrophysical properties to be estimated meaningfully. We discuss the current limitations of the methodology and suggest improvements, in particular the need to obtain higher resolutions for tighter Cores and to calibrate the simulated data to parallel laboratory Core measurements. We also describe the potential to extend the methodology to a wider range of petrophysical properties. This development could lead to a more systematic study of the assumptions, interpretations and analysis methods commonly applied within the industry and lead to better correlations between petrophysical properties and log measurements.
Mark A Knackstedt - One of the best experts on this subject based on the ideXlab platform.
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Petrophysical Characterization of Unconventional Reservoir Core At Multiple Scales
Petrophysics, 2012Co-Authors: Mark A Knackstedt, Robert Sok, Anna Carnerup, Alexandra N. Golab, Ben Young, Lutz RiepeAbstract:PETROPHYSICS, VOL. 54, NO. 3 (JUNE 2013); PAGE 216–223; 10 FIGURES Mark Knackstedt2, Anna Carnerup2, Alexandra Golab2, Rob Sok2, Ben Young2, and Lutz Riepe3 Manuscript received by Editor May 13, 2013. 1 Originally presented at the SPWLA 53rd Annual Logging Symposium, Cartagena, Colombia, June 16-20-2012, Paper F 2 Lithicon, Suite 2 Ground oor, 73 Northbourne Avenue, Canberra ACT 2600, Australia; Email: mark.knackstedt@lithicon.com, anna.carnerup@lithicon.com, alexandra.golab@lithicon.com, rob.sok@lithicon.com, ben.young@lithicon.com 3 Petronas Carigali SDN.BHD.(PCSB), KLCC Twin Towers T2, Level 11, Kuala Lumpur, Malaysia; Email: lutz_riepe@petronas. com.my Tight unconventional Reservoirs have become an increasingly common target for hydrocarbon production. Exploitation of these resources requires a comprehensive Reservoir description and characterization program to estimate reserves, identify properties that control production and predict fracturability. Multiscale imaging studies from the whole Core to the nanometer scale can aid in understanding the multiple contributions of heterogeneity, natural fracture density, pore types, porethroat connectivity, mineral and organic content and distribution to petrophysical response and production characteristics. In this paper we present three examples of the application of multiscale imaging to challenging unconventional Reservoirs: a deep, clastic tight-gas Reservoir; a fractured basement Reservoir; and coal-seam gas Reservoir. All these samples exhibit features at multiple scales, which present major challenges to petrophysical evaluation and understanding of Reservoir engineering properties. In all cases, characterization of heterogeneity and geological rock typing is undertaken at the Core scale. Mineralogy and porosity/microporosity characterization is then mapped at the pore scale with varying modes of microcomputed tomography ( CT) 3D imaging. Focusedion-beam scanning electron microscopy (FIBSEM) imaging can then be used to reveal the nanoporous structure of the key phases controlling hydrocarbon movement within the Core material. Petrophysical properties (porosity, permeability, elastic moduli) can also be computed for each key phase and the data upscaled using standard techniques. The presented case histories demonstrate that multiscale imaging and modeling provides a complimentary method to existing Core-measurement techniques via characterization of the distribution and nature of different pore types and matrix components. This can enable improved classi cation and aids the prediction of elastic and dynamic rock properties even on rock fragments that are not suitable for conventional Core analysis. In addition, the results have the potential to enhance our understanding of petrophysical, fracturing and multiphase ow processes in challenging unconventional Reservoirs with low porosities and permeabilities.
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mapping 3d pore scale fluid distributions how rock resistivity is influenced by wettability and saturation history
Petrophysics, 2010Co-Authors: Munish Kumar, Mark A Knackstedt, Shane Latham, Adrian Sheppard, Trond Varslot, Timothy Senden, Robert Sok, Christoph H ArnsAbstract:Complexities in pore scale structure, rock-fluid and fluid-fluid interactions have a profound effect on the estimation of reserves, recovery and productivity in Reservoir rocks. These complexities determine the pore scale distribution of fluids within the pore space. An example is the estimation of water saturation via resistivity measurements. Default saturation exponents (n=2) are often used in estimating saturations despite experimental laboratory results which show a wide range; 0.9
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Quantifying trapped residual oil in Reservoir Core material at the pore scale: Exploring the role of displacement rate, saturation history and wettability.
All Days, 2009Co-Authors: Munish Kumar, Timothy Senden, Adrian Sheppard, Jill Middleton, Mark A KnackstedtAbstract:Abstract At the conclusion of flooding into an oil- or gas-bearing Reservoir, a significant fraction of the original hydrocarbon in place remains in the swept region as trapped residual phase. In addition to detemining the amount of trapped phase, the microscopic distribution within the pore space of the Reservoir rock is important to gain a better understanding of recovery mechanisms, and for the design and implementation of improved or enhanced recovery processes. Despite the importance of the pore scale structure and distribution of residual oil, little quantitative information is currently available. This study presents a method to obtain this critical information. We utilize a new technique for imaging the pore-scale distribution of fluids in Reservoir Cores in three dimensions. The method allows Reservoir Core material to be imaged after flooding under different wettability conditions, saturation states and flooding rates. Oil recovery mechanisms are directly tested and the differences in the habitat of the residual fluids under different conditions are quantified. This paper describes the results of a range of flooding experiments performed on clastic and carbonate Core material of varying complexity. Variations in the remaining hydrocarbon saturation are enumerated in-situ within the pore structure as flow rates, wettability and saturation history is varied. Detailed pore scale information of the residual oil saturation is reported. Introduction Although considerable attention has been paid to the subject of residual oil, the amount of quantitative experimental information on the structure of the residual oil phase in Reservoir Core material is limited. Attempts at modelling this phenomenon are difficult due to the inherent complexity of the physics of the waterflooding process; e.g., the need to incorporate realistic fluid:fluid and fluid:solid interactions including wettability. Most methods that attempt to quantify the residual oil phase use simplistic pore micromodels, or utilize destructive techniques (pore/blob casts) to infer mechanisms of the waterflood process (Craze, 1950, Chatzis, 1983). The amount of trapped phase in a Reservoir rock after flooding and its microscopic distribution within the pore space is required to gain a better understanding of recovery mechanisms and for the design and implementation of improved or enhanced recovery processes. In this paper we attempt to address this issue through the application of a technique where one can image the pore scale distribution of different fluid phases in-situ within the pore space of Reservoir Cores. A key feature of this method is that experiments can be performed on the identical Core under multiple states i.e. we perform the experiments on the same pore space in a non-destructive manner. In this way, the habitat of the residual fluids under varying conditions can be directly quantified, without ambiguity due to variations in the pore structure. In parallel to the role micromodels (Lenormand et al., 2003) have played in understanding the displacement mechanisms and complex multiphase flow properties of porous media in two dimensions, this development extends the concept of pore scale visualization of multiphase fluid flow to three dimensions. As the technique used is non-destructive, the detailed structure of the residual trapped phase can be readily described with repect to its location within the pore space. Additionally, the size distributions of residual oil blobs, features of blob shape and dimensions can be easily enumerated and compared under variable flooding conditions. These results provide important understanding of the habitat of the residual oil and a platform for the testing and calibration of pore scale modelling efforts for multiphase flow.
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digital rock physics 3d imaging of Core material and correlations to acoustic and flow properties
Geophysics, 2009Co-Authors: Mark A Knackstedt, Shane Latham, Mahyar Madadi, Adrian Sheppard, Trond Varslot, Christoph H ArnsAbstract:3D X-ray microtomographic imaging and visualization of Core material at the pore scale and subsequent analysis of petrophysical properties can give important insight to understanding properties of Reservoir Core material. 3D images allow one to map in detail the pore and grain structure and interconnectivity of Core material. Numerical calculations on image data are in agreement with experimental data for flow and elastic properties on simple Core material. This development forms the basis for developing more meaningful structure-property correlations in rock.
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Mapping Fluid Distributions In 3D At The Pore Scale: Quantifying The Influence Of Wettability And Saturation History On Rock Resistivity
2009Co-Authors: Munish Kumar, Mark A Knackstedt, Shane Latham, Adrian Sheppard, Trond Varslot, Timothy Senden, Robert Sok, Christoph H ArnsAbstract:Complexities in pore scale structure, rock-fluid and fluid-fluid interactions have a profound effect on the estimation of reserves, Reservoir recovery and productivity in Reservoir Core material. These complexities determine the pore scale distribution of fluids within the pore space, which, in turn, determine the petrophysical response of the rock. A very important example is the estimation of water saturation via resistivity measurements. Default saturation exponents (n=2) are often used in estimating saturations despite numerous measurements which have shown that n can depend strongly on the rock type, mineralogy, saturation history and wettability. NonArchie behavior is reported frequently. Experimental laboratory results for the resistivity response of clastic and carbonate Reservoir Cores under varying wettability states have exhibited a range of saturation exponents; 1
Barry Bennett - One of the best experts on this subject based on the ideXlab platform.
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deterioration of oil quality during sample storage are stored Reservoir Core samples a viable resource for oil viscosity determination
Fuel, 2019Co-Authors: Barry Bennett, Chunqing Jiang, Stephen R LarterAbstract:Abstract The physical and chemical properties of oil residing in Reservoir Core samples are strongly susceptible to evaporative processes during storage. In a case study from the Peace River oil sands of Alberta, we performed dead oil viscosity measurements on oils recovered by mechanical extraction of fresh Core, the equivalent Cores stored for 7 months frozen plus 3 months at ambient conditions (time 1) and for 7 months frozen plus 8 months at ambient conditions (time 2). The dead oil viscosity of oil recovered from fresh Core material (8100 cP at 20 °C) was more than an order of magnitude lower than that of the oil subsequently recovered from an equivalent Core sample stored frozen for 7 months and then at ambient temperature for 8 months (313,500 cP at 20 °C). The evaporation of light hydrocarbons such as toluene and xylenes during storage is a continuous process responsible for progressive increase in dead oil viscosity. Meanwhile, when comparing the oils recovered from fresh Core and aged Core samples, the composition of the heavy (low volatility) hydrocarbons remains essentially the same. Because biodegradation is the primary control on oil viscosity and variation in hydrocarbon compositions for this oil sample suite, partial least squares models based on viscosity versus geochemical data may still be used to predict viscosity. Although the physical properties of the oil may be compromised during storage, the distributions of the high molecular weight components retain characteristics, similar to a bar code, that are inherited and representative of the original (fresh) Core sample. Therefore, with the proviso that the distributions of high molecular weight components are comparable between fresh Cores and aged Cores, the viscosity of oil residing in stored Core samples can be effectively restored by chemometric-based correlation methods.
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The isolation, occurrence and origin of fluorenones in crude oils and rock extracts
Organic Geochemistry, 2000Co-Authors: Barry Bennett, Steve LarterAbstract:Abstract A rapid method for the analysis of fluorenones in crude oils and Reservoir Core extracts based on solid phase extraction and GC–MS is described. A detailed Reservoir study involving analysis of both fluids and Core extracts was performed and variations in the distributions of fluorenones between Reservoir phases are discussed. Concentrations of fluorenones in Reservoir Core extracts are often very high, which may reflect sorption processes after fluorenone production but in general, fluorenone abundance in flowed oils seems to be sporadic and may be related to sample age and storage history with recent production oils having lower fluorenone concentrations than corresponding older Drill Stem Test oils. While a geochemical origin for fluorenones cannot be eliminated in some settings, we are concerned that these compounds may be frequently formed sporadically as a result of post-sampling oxidation.