scholarly journals Thermal Diffusion Characteristics in Permafrost during the Exploitation of Gas Hydrate

Geofluids ◽  
2021 ◽  
Vol 2021 ◽  
pp. 1-10
Author(s):  
Yusen Wei ◽  
Youming Xiong ◽  
Zhiqiang Liu ◽  
Jingsheng Lu
Keyword(s):  
Phase Transition ◽  
Pore Size Distribution ◽  
Pore Size ◽  
Size Distribution ◽  
Thermal Diffusion ◽  
Gas Hydrate ◽  
Reservoir Rock ◽  
Maximum Temperature ◽  
Endothermic Reaction ◽  
Surface Relaxivity

Methane hydrate is the vast potential resources of natural gas in the permafrost and marine areas. Due to the occurrence of phase transition, the gas hydrate is dissociated into gas and water and absorbs lots of heat. The incomprehensive knowledge of endothermic reaction in permafrost sediments still restricted the production efficiency of hydrate commercial development. This endothermic reaction leads to a complex thermal diffusion in permafrost, which directly influences the phase transition in turn. In this research, the heat during the exploitation is transferred in two forms (specific heat and latent heat). Besides, the melting point is not constant but depends on the pore size of the reservoir rock. According to these features, a thermal diffusion model with phase transition is established. To calculate the governing equation, the pore size distribution is obtained by using the nuclear magnetic resonance (NMR) method. The heating tests are conducted and simulated to calibrate the coefficient (i.e., transverse surface relaxivity) of NMR. Then, the temperature field evolution of the hydrate reservoir during the exploitation is simulated by using the calibrated values. The results show that the temperature curves have a typical plateau related to the pore size distribution, which is effective to obtain the surface relaxivity. The heat transfer is remarkably limited by the endothermic effect of the phase transition. The hydrate recovery efficiency may depend largely on the heating capacity of the engineering operation and the rate of gas production. Compared to the conventional petroleum industry, it is significant to control the maximum temperature and temperature distribution in engineering operations during hydrate development. This research on the temperature behavior during onshore permafrost hydrate production could provide the theoretical support to control heat behavior of offshore hydrate production.

Joint inversion of nuclear magnetic resonance data from partially saturated rocks using a triangular pore model

Geophysics ◽  
2018 ◽  
Vol 83 (4) ◽  
pp. JM15-JM28 ◽  
Author(s):  
Thomas Hiller ◽  
Norbert Klitzsch
Keyword(s):  
Nuclear Magnetic Resonance ◽  
Magnetic Resonance ◽  
Pore Size Distribution ◽  
Pore Size ◽  
Size Distribution ◽  
Joint Inversion ◽  
Nmr Relaxation ◽  
Relaxation Data ◽  
Surface Relaxivity ◽  
Partially Saturated

Measurement of nuclear magnetic resonance (NMR) relaxation is a well-established laboratory/borehole method to characterize the storage and transport properties of rocks due to its direct sensitivity to the corresponding pore-fluid content (water/oil) and pore sizes. Using NMR, the correct estimation of, e.g., permeability strongly depends on the underlying pore model. Usually, one assumes spherical or cylindrical pores for interpreting NMR relaxation data. To obtain surface relaxivity and thus, the pore-size distribution, a calibration procedure by, e.g., mercury intrusion porosimetry or gas adsorption has to be used. Recently, a joint inversion approach was introduced that used NMR measurements at different capillary pressures/saturations (CPS) to derive surface relaxivity and pore-size distribution (PSD) simultaneously. We further extend this approach from a bundle of parallel cylindrical capillaries to capillaries with triangular cross sections. With this approach, it is possible to account for residual or trapped water within the pore corners/crevices of partially saturated pores. In addition, we have developed a method that allows determining the shape of these triangular capillaries by using NMR measurements at different levels of drainage and imbibition. We show the applicability of our approach on synthetic and measured data sets and determine how the combination of NMR and CPS significantly improves the interpretation of NMR relaxation data on fully and partially saturated porous media.

A New Approach for Building Composite Cores for Corefloods in Complex Carbonate Rocks

2021 ◽  
Author(s):  
Yildiray Cinar ◽  
Ahmed Zayer ◽  
Naseem Dawood ◽  
Dimitris Krinis
Keyword(s):  
Pore Size Distribution ◽  
Pore Size ◽  
Capillary Pressure ◽  
Size Distribution ◽  
Carbonate Reservoir ◽  
Reservoir Rock ◽  
Rock Types ◽  
Pore Structures ◽  
Irreducible Water Saturation ◽  
Wide Range

Abstract Carbonate reservoir rocks are composed of complex pore structures and networks, forming a wide range of sedimentary facies. Considering this complexity, we present a novel approach for a better selection of coreflood composites. In this approach, reservoir plugs undergo a thorough filtration process by completing several lab tests before they get classified into reservoir rock types. Those tests include conventional core analysis (CCA), liquid permeability, plug computed tomography (CT), nuclear magnetic resonance (NMR), end-trim mercury injection capillary pressure (MICP), X-ray diffraction (XRD), thin-section analysis (TS), scanning electron microscopy (SEM), and drainage capillary pressure (Pc). We recommend starting with a large pool of plugs and narrowing down the selection as they complete different stages of the screening process. The CT scans help to exclude plugs exhibiting composite-like behavior or containing vugs and fractures that potentially influence coreflood results. After that, the plugs are categorized into separate groups representing the available reservoir rock types. Then, we look into each rock type and determine whether the selected plugs share similar pore-structures, rock texture, and mineral content. The end-trim MICP is usually helpful in clustering plugs having similar pore-throat size distributions. Nevertheless, it also poses a challenge because it may not represent the whole plug, especially for heterogeneous carbonates. In such a case, we recommend harnessing the NMR capabilities to verify the pore-size distribution. After pore-size distribution verification, plugs are further screened for textural and mineral similarity using the petrographic data (XRD, TS, and SEM). Finally, we evaluate the similarity of brine permeability (Kb), irreducible water saturation (Swir) from Pc, and effective oil permeability data at Swir (Koe, after wettability restoration for unpreserved plugs) before finalizing the composite selection. The paper demonstrates significant aspects of applying the proposed approach to carbonate reservoir rock samples. It integrates geology, petrophysics, and reservoir engineering elements when deciding the best possible composite for coreflood experiments. By practicing this workflow, we also observe considerable differences in rock types depending on the data source, suggesting that careful use of end-trim data for carbonates is advisable compared to more representative full-plug MICP and NMR test results. In addition, we generally observe that Kb and Koe are usually lower than the Klinkenberg permeability with a varying degree that is plug-specific, highlighting the benefit of incorporating these measurements as additional criteria in coreflood composite selection for carbonate reservoirs.

scholarly journals Fractal Properties of Various Clay Minerals Obtained from SEM Images

Geofluids ◽  
2021 ◽  
Vol 2021 ◽  
pp. 1-18
Author(s):  
Naser Golsanami ◽  
Shanilka Gimhan Fernando ◽  
Madusanka Nirosh Jayasuriya ◽  
Weichao Yan ◽  
Huaimin Dong ◽  
...  
Keyword(s):  
Pore Size Distribution ◽  
Pore Size ◽  
Size Distribution ◽  
Clay Minerals ◽  
Pore Space ◽  
Reservoir Rock ◽  
Distribution Area ◽  
Sem Images ◽  
Fractal Properties ◽  
Internal Pore

Clay minerals significantly alter the pore size distribution (PSD) of the gas hydrate-bearing sediments and sandstone reservoir rock by adding an intense amount of micropores to the existing intragranular pore space. Therefore, in the present study, the internal pore space of various clay groups is investigated by manually segmenting Scanning Electron Microscopy (SEM) images. We focused on kaolinite, smectite, chlorite, and dissolution holes and characterized their specific pore space using fractal geometry theory and parameters such as pore count, pore size distribution, area, perimeter, circularity, and density. Herein, the fractal properties of different clay groups and dissolution holes were extracted using the box counting technique and were introduced for each group. It was observed that the presence of clays complicates the original PSD of the reservoir by adding about 1.31-61.30 pores/100 μm2 with sizes in the range of 0.003-87.69 μm2. Meanwhile, dissolution holes complicate the pore space by adding 4.88-8.17 extra pores/100 μm2 with sizes in the range of 0.06-119.75 μm2. The fractal dimension ( D ) and lacunarity ( L ) values of the clays’ internal pore structure fell in the ranges of 1.51-1.85 and 0.18-0.99, respectively. Likewise, D and L of the dissolution holes were in the ranges of, respectively, 1.63-1.65 and 0.56-0.62. The obtained results of the present study lay the foundation for developing improved fractal models of the reservoir properties which would help to better understand the fluid flow, irreducible fluid saturation, and capillary pressure. These issues are of significant importance for reservoir quality and calculating the accurate amount of producible oil and gas.

Effect of Pore-Size Distribution on Phase Transition of Hydrocarbon Mixtures in Nanoporous Media

SPE Journal ◽  
2016 ◽  
Vol 21 (06) ◽  
pp. 1981-1995 ◽  
Author(s):  
Lei Wang ◽  
Xiaolong Yin ◽  
Keith B. Neeves ◽  
Erdal Ozkan
Keyword(s):  
Phase Transition ◽  
Phase Change ◽  
Pore Size Distribution ◽  
Phase Behavior ◽  
Pore Size ◽  
Capillary Pressure ◽  
Size Distribution ◽  
Hydrocarbon Mixtures ◽  
Nanoporous Media ◽  
Light Oil

Summary Pore sizes of many shale-oil and tight gas reservoirs are in the range of nanometers. In these pores, capillary pressure and surface forces can make the phase behavior of hydrocarbon mixtures different from that characterized in pressure/volume/temperature (PVT) cells. Many existing phase-behavior models use a single pore size to describe the effect of confinement on phase behavior. To follow up with our earlier theoretical studies and experimental observations, this research investigates the effect of pore-size distribution. By use of a vapor/liquid equilibrium model that considers the effect of capillary pressure, we present a procedure to simulate the sequence of phase changes in a porous medium caused by a pore-size distribution. This procedure is used to simulate depressurizations of a light oil and a retrograde gas confined inside nanoporous media, the pore-size distributions of which are characteristic of tight reservoirs. The fluid compositions are representative of typical reservoir fluids. Predictions of the model show that phase transition in nanoporous medium with pore-size distribution is not described by a single phase boundary. The initial phase change in the large pores alters the composition of the remaining fluid, and, in turn, suppresses the next phase change. For the two cases studied, models with and without capillary pressure gave similar predictions. For light oil, capillary pressure still noticeably increased the level of supersaturation, and the critical gas saturation had a strong influence on the properties of produced fluids. For retrograde gas, the effect of capillary pressure was insignificant because of the low interfacial tension (IFT). Despite the choice of fluids, calculations indicate that the smallest pores are probably always occupied by hydrocarbon liquid during depressurization.

scholarly journals Effect of Benzyltrimethylammonium Ion as a Co-directing Agent on Phase Transitions in a Nanostructure Silica/Surfactant Composite

2010 ◽  
Vol 7 (4) ◽  
pp. 1407-1411 ◽  
Author(s):  
Alireza Badiei ◽  
Hassan Goldooz ◽  
Ghodsi Mohammadi Ziarani
Keyword(s):  
Phase Transition ◽  
Phase Transformation ◽  
Phase Transitions ◽  
Pore Size Distribution ◽  
Surface Charge ◽  
Pore Size ◽  
Size Distribution ◽  
Elemental Analysis ◽  
Constant Ph

Effect of benzyltrimethylammonium ion as a co directing agent in phase transition from hexagonal to cubic and lamellar mesophases was studied in the constant pH at 130 °C. This phase transformation was carried out in constant surface charge and pore size distribution (2 nm). Influence of BTMA+ions between head and tail of surfactant and phase transformation were observed by using the XRD and elemental analysis.

scholarly journals Permeability and Rock Fabric from Wireline Logs, Arab-D Reservoir, Ghawar Field, Saudi Arabia

GeoArabia ◽  
2001 ◽  
Vol 6 (4) ◽  
pp. 619-646
Author(s):  
F. Jerry Lucia ◽  
James W. Jennings ◽  
Michael Rahnis ◽  
Franz O. Meyer
Keyword(s):  
Pore Size Distribution ◽  
Pore Size ◽  
Size Distribution ◽  
Spatial Information ◽  
Water Saturation ◽  
Reservoir Rock ◽  
Petrophysical Properties ◽  
Rock Fabric ◽  
Interparticle Porosity ◽  
Wireline Logs

ABSTRACT The goal of reservoir characterization is to distribute petrophysical properties in 3-D. Porosity, permeability, and saturation values have no intrinsic spatial information and must be linked to a 3-D geologic model to be distributed in space. This link is provided by relating petrophysical properties to rock fabrics. The vertical succession of rock fabrics was shown to be useful in constructing a geologic framework for distributing porosity, permeability, and saturation in 3-D. Permeability is perhaps the most difficult petrophysical property to obtain and image because its calculation from wireline logs requires the estimation of pore-size distribution. In this study of the Arab-D reservoir, rock fabric and interparticle porosity were used to estimate pore-size distribution. Cross-plots of water saturation and porosity, calibrated with rock-fabric descriptions, formed the basis for determining the distribution of rock fabric and pore size from resistivity and porosity logs. Interparticle porosity was obtained from travel-time/porosity, cross-plot relationships. A global porosity-permeability transform that related rock fabric, interparticle porosity, and permeability was the basis for calculating permeability from wireline logs. Calculated permeability values compared well with core permeability. In uncored wells, permeability was summed vertically and the horizontal permeability profile compared with flow-meter data. The results showed good correlation in most wells.

scholarly journals Modelling Methane Hydrate Saturation in Pores: Capillary Inhibition Effects

Energies ◽  
2021 ◽  
Vol 14 (18) ◽  
pp. 5627
Author(s):  
Maria De La Fuente ◽  
Jean Vaunat ◽  
Héctor Marín-Moreno
Keyword(s):  
Pore Size Distribution ◽  
Pore Size ◽  
Size Distribution ◽  
Gas Hydrate ◽  
Hydrate Formation ◽  
Clapeyron Equation ◽  
Fine Grained ◽  
Chemical Potentials ◽  
Hydrate Saturation ◽  
Global Inventory

Experimental and field observations evidence the effects of capillarity in narrow pores on inhibiting the thermodynamic stability of gas hydrates and controlling their saturation. Thus, precise estimates of the gas hydrate global inventory require models that accurately describe gas hydrate stability in sediments. Here, an equilibrium model for hydrate formation in sediments that accounts for capillary inhibition effects is developed and validated against experimental data. Analogous to water freezing in pores, the model assumes that hydrate formation is controlled by the sediment pore size distribution and the balance of capillary forces at the hydrate–liquid interface. To build the formulation, we first derive the Clausius–Clapeyron equation for the thermodynamic equilibrium of methane and water chemical potentials. Then, this equation is combined with the van Genuchten’s capillary pressure to relate the thermodynamic properties of the system to the sediment pore size distribution and hydrate saturation. The model examines the influence of the sediment pore size distribution on hydrate saturation through the simulation of hydrate formation in sand, silt, and clays, under equilibrium conditions and without mass transfer limitations. The results show that at pressure–temperature conditions typically found in the seabed, capillary effects in very fine-grained clays can limit the maximum hydrate saturation below 20% of the host sediment porosity.

scholarly journals Reservoir rock classification, Arab-D reservoir, Ghawar field, Saudi Arabia

GeoArabia ◽  
2003 ◽  
Vol 8 (3) ◽  
pp. 435-462
Author(s):  
Dave L. Cantrell ◽  
Royal M. Hagerty
Keyword(s):  
Pore Size Distribution ◽  
Pore Size ◽  
Size Distribution ◽  
Rock Type ◽  
Reservoir Rock ◽  
Rock Classification ◽  
Crystal Texture ◽  
Rock Types ◽  
Lime Mud ◽  
Ghawar Field

ABSTRACT An integrated petrographic and petrophysical study of Arab-D carbonates in Ghawar field has provided a new reservoir rock classification. This classification provides a simple but practical method of dividing the complex carbonate rocks of the Arab-D into meaningful reservoir rock types. Each rock type has a distinct pore network as defined by porosity-permeability relationships and capillarity expressed as pore-size distributions and J-function curves. The classification divides the Arab-D carbonates into seven limestone and four dolomite rock types. The amount of matrix (lime mud) and the pore types are the primary controlling parameters for the limestones. The dolomites are divided according to their crystal texture. The seven limestone reservoir rock types are based on the values of five petrographic parameters: (1) the amount of cement, (2) the amount of matrix (lime mud), (3) the grain sorting, (4) the dominant pore type, and (5) the size of the largest molds. The amount of matrix is the most important of these five parameters. In general terms, six of these seven types fall into two broad families, A and B, each of which can then be subdivided into three members (Types I, II, and III) according to their matrix content. The first family, A, is a fairly coarse-grained, poorly sorted rock with relatively large molds. The second family, B, is a generally fine to medium-grained, well sorted rock with few or small molds. The seventh rock type contains more than 10 percent cement which modifies the pore size distribution enough to warrant a separate reservoir rock type. Each of the reservoir rock types exhibits a distinctive pore-size distribution and, in turn, Leverett J-function or capillarity. The seven types are also characterized by distinctive porosity-permeability relationships. The four dolomite reservoir rock types are classified according to their dolomite crystal texture, although stratigraphic position and porosity can also be effective in their classification. The four textures are: fabric preserving (Vfp), sucrosic (Vs), intermediate (Vi) and mosaic (Vm). The Vfp dolomite is only found in Zone 1 of the Arab-D where it is the major dolomite type. Vs dolomite occurs in dolomites with more than 12 percent porosity, Vm less than 5 percent and Vi between 5 and 12 percent. Vfp dolomites have pore systems similar to their precursor limestone but the pore systems of the other dolomite types are unique. A significant finding of this evaluation is that the micropore system in all major limestone rock types in Zones 1 and 2 (upper Arab-D) is consistently an order of magnitude larger than for the same rock types in Zones 3 and 4 (lower Arab-D). The increase in size is believed to be a result of increased leaching in the upper Arab-D. This difference suggests that rocks of similar type from the upper and lower Arab-D will behave differently in terms of their fluid flow and saturation characteristics, and will have different ultimate recoveries.

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