scholarly journals Nano- to Millimeter Scale Morphology of Connected and Isolated Porosity in the Permo-Triassic Khuff Formation of Oman

Geosciences ◽  
2019 ◽  
Vol 10 (1) ◽  
pp. 7 ◽  
Author(s):  
Jörg Smodej ◽  
Laurent Lemmens ◽  
Lars Reuning ◽  
Thomas Hiller ◽  
Norbert Klitzsch ◽  
...  
Keyword(s):  
Pore Size ◽  
Ion Beam ◽  
Total Porosity ◽  
Oil And Gas Industry ◽  
Effective Porosity ◽  
Carbonate Reservoir ◽  
Size Spectrum ◽  
Pore Connectivity ◽  
Rock Types ◽  
Laboratory Techniques

Carbonate reservoirs form important exploration targets for the oil and gas industry in many parts of the world. This study aims to differentiate and quantify pore types and their relation to petrophysical properties in the Permo-Triassic Khuff Formation, a major carbonate reservoir in Oman. For that purpose, we have employed a number of laboratory techniques to test their applicability for the characterization of respective rock types. Consequently, a workflow has been established utilizing a combined analysis of petrographic and petrophysical methods which provide the best results for pore-system characterization. Micro-computed tomography (µCT) analysis allows a representative 3D assessment of total porosity, pore connectivity, and effective porosity of the ooid-shoal facies but it cannot resolve the full pore-size spectrum of the highly microporous mud-/wackestone facies. In order to resolve the smallest pores, combined mercury injection capillary pressure (MICP), nuclear magnetic resonance (NMR), and BIB (broad ion beam)-SEM analyses allow covering a large pore size range from millimeter to nanometer scale. Combining these techniques, three different rock types with clearly discernible pore networks can be defined. Moldic porosity in combination with intercrystalline porosity results in the highest effective porosities and permeabilities in shoal facies. In back-shoal facies, dolomitization leads to low total porosity but well-connected and heterogeneously distributed vuggy and intercrystalline pores which improves permeability. Micro- and nanopores are present in all analyzed samples but their contribution to effective porosity depends on the textural context. Our results confirm that each individual rock type requires the application of appropriate laboratory techniques. Additionally, we observe a strong correlation between the inverse formation resistivity factor and permeability suggesting that pore connectivity is the dominating factor for permeability but not pore size. In the future, this relationship should be further investigated as it could potentially be used to predict permeability from wireline resistivity measured in the flushed zone close to the borehole wall.

Utilizing NMR Workflow to Optimize Power Water Injector Placement in the Presence of Tar Barriers

2021 ◽  
Author(s):  
Gabor Hursan ◽  
Mohammed Sahhaf ◽  
Wala’a Amairi
Keyword(s):  
Spectral Analysis ◽  
Pore Size ◽  
Real Time ◽  
Total Porosity ◽  
Carbonate Reservoir ◽  
Wettability Alteration ◽  
Well Placement ◽  
Carbonate Formation ◽  
Fluid Saturation ◽  
Rock Quality

Abstract The objective of this work is to optimize the placement of horizontal power water injector (PWI) wells in stratified heterogeneous carbonate reservoir with tar barriers. The key to successful reservoir navigation is a reliable real-time petrophysical analysis that resolves rock quality variations and differentiates tar barriers from lighter hydrocarbon intervals. An integrated workflow has been generated based on logging-while drilling (LWD) triple combo and Nuclear Magnetic Resonance (NMR) logging data for fluid identification, tar characterization and permeability prediction. The workflow has three steps; it starts with the determination of total porosity using density and neutron logs, the calculation of water-filled porosity from resistivity measurements and an additional partitioning of porosity into bound and free fluid volumes using the NMR data. Second, the total and water-filled porosity, the NMR bound fluid and NMR total porosity are used as inputs in a hydrocarbon compositional and viscosity analysis of hydrocarbon-bearing zones for the recognition of tar-bearing and lighter hydrocarbon intervals. Third, in the lighter hydrocarbon intervals, NMR logs are further analyzed using a multi-cutoff spectral analysis to identify microporous and macroporous zones and to calculate the NMR mobility index. The ideal geosteering targets are highly macroporous rocks containing no heavy hydrocarbons. In horizontal wells, the method is validated using formation pressure while drilling (FPWD) measurements. The procedure has been utilized in several wells. The original well path of the first injector was planned to maintain a safe distance above an anticipated tar-bearing zone. Utilizing the new real-time viscosity evaluation, the well was steered closer to the tar zone several feet below the original plan, setting an improved well placement protocol for subsequent injectors. In the water- or lighter hydrocarbon-bearing zones, spectral analysis of NMR logs clearly accentuated micro- and macroporous carbonate intervals. The correlation between pore size and rock quality has been corroborated by FPWD mobility measurements. In one well, an extremely slow NMR relaxation may indicate wettability alteration in a macroporous interval. An integrated real-time evaluation of porosity, fluid saturation, hydrocarbon viscosity and pore size has enhanced well placement in a heterogeneous carbonate formation where tar barriers are also present. The approach increased well performance and substantially improved reservoir understanding.

Microstructural Analysis of Iberian Expanded Clay Aggregates

2012 ◽  
Vol 18 (5) ◽  
pp. 1190-1208 ◽  
Author(s):  
J. Alexandre Bogas ◽  
António Mauricio ◽  
M.F.C. Pereira
Keyword(s):  
Water Absorption ◽  
Pore Size ◽  
Mercury Porosimetry ◽  
Microstructural Analysis ◽  
Spatial Arrangement ◽  
Outer Shell ◽  
Size Spectrum ◽  
Pore Connectivity ◽  
Joint Consideration ◽  
Clay Aggregates

AbstractThis article presents a detailed study of the microstructure of Iberian expanded clay lightweight aggregates (LWA). Other than more commonly used mercury porosimetry (MP) and water absorption methods, the experimental study involves optical microscopy, scanning electron microscopy (SEM), and microtomography (μ-CT). Pore connectivity and how it is deployed are shown to some degree, and the pore size spectrum is estimated. LWA are in general characterized by a dense outer shell up to 200 μm thick, encasing an inner cellular structure of 10–100 times bigger pore size. Aggregate pore sizes may span from some hundreds of nanometers up to over 1 mm, though the range of 1–25 μm is more typical. A noteworthy fraction of these pores is closed, and they are mainly up to 1 μm. It is also shown that macropore spatial arrangement is affected by the manufacturing process. A step forward is given to understanding how the outer shell and the inner pore network influence the mechanical and physical LWA properties, particularly the density and water absorption. The joint consideration of μ-CT and SEM seems to be the most appropriate methodology to study LWA microstructure. MP analysis is likely to distort LWA pore spectrum assessment.

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.

A Quantitative Approach To Characterize Porosity Structure From Borehole Electrical Images and Its Application in a Carbonate Reservoir in the Tazhong Area, Tarim Basin

2016 ◽  
Vol 19 (01) ◽  
pp. 018-023 ◽  
Author(s):  
Fu Hai-cheng ◽  
Zou Chang-chun ◽  
Li Ning ◽  
Xiao Cheng-wen ◽  
Zhang Cheng-sen ◽  
...  
Keyword(s):  
Tarim Basin ◽  
Total Porosity ◽  
Effective Porosity ◽  
Carbonate Reservoir ◽  
Test Results ◽  
Well Test ◽  
Porosity Structure ◽  
Two Parameters ◽  
The Right ◽  
Low Porosity

Summary For a carbonate reservoir that has low porosity, its validity cannot simply be measured by its total porosity. Therefore, one must find more-effective porosity parameters to indicate reservoir validity. Two parameters that reflect the porosity spectrum's shape are proposed in this paper to characterize the porosity structure from borehole electrical images. One is the length of the right-porosity spectrum (LRPS), and the other is the root mean square (RMS) of the right-porosity spectrum (RMSRPS). Subsequently, the validity of a carbonate reservoir was considered by use of these two parameters. The logging evaluation, processing, and interpretation of multiple wells in a fractured/vuggy reservoir with low porosity in the Tarim Basin indicate that these two parameters reflect the variation of pore structures better than conventional methods, and they agree better with the well-test results.

A comprehensive evaluation of the productive formation collector of the Kanevskoye field

2021 ◽  
pp. 25-36
Author(s):  
I. I. Bosikov ◽  
A. I. Mazko ◽  
A. V. Mayer
Keyword(s):  
Oil And Gas ◽  
Comprehensive Evaluation ◽  
Total Porosity ◽  
Oil And Gas Industry ◽  
Particle Size Analysis ◽  
Core Sample ◽  
Effective Porosity ◽  
Comprehensive Assessment ◽  
Size Analysis ◽  
Resource Base

At the present stage, the development of the oil and gas industry of the Russian Federation is impossible without replenishing the resource base, and therefore an urgent task is to conduct research, prospecting and evaluating petroleum potential in undiscovered areas of fields. The aim of the study is to conduct a comprehensive assessment of the reservoir of the productive formation of the Kanevskoye field. We have carried out mineralogical and petrographic studies, laboratory studies to assess the effective porosity of the core sample by the saturation method, particle size analysis, X-ray diffraction analysis. Our studies have shown that the considered initial sands under consideration, which formed the reservoir rocks of the productive horizon of the Kanevskoye field, were formed by coastal or beach type marine sediments. This is confirmed by the poorly rounded shape of the grains and the presence of glauconite in the rocks. The studied core sample is a fine-grained glauconite-feldspar-quartz sandstone with an admixture of aleurite fraction, with semi-rounded grains, pelitic cement, basal and porous-basal, silt-psammitic structure. The total porosity is 14.3 %. A comprehensive assessment of the reservoir of the productive formation of the Kanevskoye field has been carried out. The reservoir is productive. Therefore, it is necessary to make a project for conducting geological exploration.

scholarly journals Quantification of pore-size spectrums by solute breakthrough curves

2011 ◽  
Vol 8 (5) ◽  
pp. 8373-8397
Author(s):  
S. Erşahin
Keyword(s):  
Particle Size ◽  
Porous Medium ◽  
Pore Size ◽  
Pore Water ◽  
Pore Radius ◽  
Total Porosity ◽  
Breakthrough Curves ◽  
Water Velocity ◽  
Size Spectrum ◽  
Pore Water Velocity

Abstract. Breakthrough of conservative tracers may be used to quantify pore-size spectrum and pore-water velocity distributions in a porous medium. In this study, a theory was proposed to calculate pore-water velocity and corresponding pore-size spectrum in porous media, and its application was demonstrated. Miscible displacement tests of chloride were conducted with sand columns (5 cm id and 5 cm length), repacked with washed sand with a particle size of 2–1, 1–0.45, 0.45–0.325 and <0.325 mm in diameter. The resulting breakthrough curves were divided into approximately 20 segments, and for each segment, a concentration of Cl in an out-flowing effluent was used with corresponding effluent volume and travel time to calculate corresponding pore water velocity (v) and pore-radius. Mean v (vb) calculated for a column was approximated by geometric averaging the calculated v-values for the BTC. To validate the developed model, laboratory measured and approximated values of vb were compared. The correlation analysis conducted between measured and approximated vb resulted in a correlation coefficient of r = 0.89 (P < 0.01). The results revealed that size distribution of effective pores could be quite different even in replicates of small sand columns, which are highly similar in particle-size and total porosity.

Petrographic and Petrophysical Characteristics of the Upper Devonian Three Forks Formation, Southern Nesson Anticline, North Dakota

2017 ◽  
Vol 54 (3) ◽  
pp. 181-201
Author(s):  
Rebecca Johnson ◽  
Mark Longman ◽  
Brian Ruskin
Keyword(s):  
Relaxation Time ◽  
Pore Size ◽  
Water Saturation ◽  
Average Pore Size ◽  
Total Porosity ◽  
Average Pore ◽  
Pore Sizes ◽  
Three Forks Formation ◽  
Three Forks ◽  
Intercrystalline Pores

The Three Forks Formation, which is about 230 ft thick along the southern Nesson Anticline (McKenzie County, ND), has four “benches” with distinct petrographic and petrophysical characteristics that impact reservoir quality. These relatively clean benches are separated by slightly more illitic (higher gamma-ray) intervals that range in thickness from 10 to 20 ft. Here we compare pore sizes observed in scanning electron microscope (SEM) images of the benches to the total porosity calculated from binned precession decay times from a suite of 13 nuclear magnetic resonance (NMR) logs in the study area as well as the logarithmic mean of the relaxation decay time (T2 Log Mean) from these NMR logs. The results show that the NMR log is a valid tool for quantifying pore sizes and pore size distributions in the Three Forks Formation and that the T2 Log Mean can be correlated to a range of pore sizes within each bench of the Three Forks Formation. The first (shallowest) bench of the Three Forks is about 35 ft thick and consists of tan to green silty and shaly laminated dolomite mudstones. It has good reservoir characteristics in part because it was affected by organic acids and received the highest oil charge from the overlying lower Bakken black shale source rocks. The 13 NMR logs from the study area show that it has an average of 7.5% total porosity (compared to 8% measured core porosity), and ranges from 5% to 10%. SEM study shows that both intercrystalline pores and secondary moldic pores formed by selective partial dissolution of some grains are present. The intercrystalline pores are typically triangular and occur between euhedral dolomite rhombs that range in size from 10 to 20 microns. The dolomite crystals have distinct iron-rich (ferroan) rims. Many of the intercrystalline pores are partly filled with fibrous authigenic illite, but overall pore size typically ranges from 1 to 5 microns. As expected, the first bench has the highest oil saturations in the Three Forks Formation, averaging 50% with a range from 30% to 70%. The second bench is also about 35 ft thick and consists of silty and shaly dolomite mudstones and rip-up clast breccias with euhedral dolomite crystals that range in size from 10 to 25 microns. Its color is quite variable, ranging from green to tan to red. The reservoir quality of the second bench data set appears to change based on proximity to the Nesson anticline. In the wells off the southeast flank of the Nesson anticline, the water saturation averages 75%, ranging from 64% to 91%. On the crest of the Nesson anticline, the water saturation averages 55%, ranging from 40% to 70%. NMR porosity is consistent across the entire area of interest - averaging 7.3% and ranging from 5% to 9%. Porosity observed from samples collected on the southeast flank of the Nesson Anticline is mainly as intercrystalline pores that have been extensively filled with chlorite clay platelets. In the water saturated southeastern Nesson Anticline, this bench contains few or no secondary pores and the iron-rich rims on the dolomite crystals are less developed than those in the first bench. The chlorite platelets in the intercrystalline pores reduce average pore size to 500 to 800 nanometers. The third bench is about 55 ft thick and is the most calcareous of the Three Forks benches with 20 to 40% calcite and a proportionate reduction in dolomite content near its top. It is also quite silty and shaly with a distinct reddish color. Its dolomite crystals are 20 to 50 microns in size and partly abraded and dissolved. Ferroan dolomite rims are absent. This interval averages 7.1% porosity and ranges from 5% to 9%, but the pores average just 200 nanometers in size and occur mainly as microinterparticle pores between illite flakes in intracrystalline pores in the dolomite crystals. This interval has little or no oil saturation on the southern Nesson Anticline. Unlike other porosity tools, the NMR tool is a lithology independent measurement. The alignment of hydrogen nuclei to the applied magnetic field and the subsequent return to incoherence are described by two decay time constants, longitudinal relaxation time (T1) and transverse relaxation time (T2). T2 is essentially the rate at which hydrogen nuclei lose alignment to the external magnetic field. The logarithmic mean of T2 (T2 Log Mean) has been correlated to pore-size distribution. In this study, we show that the assumption that T2 Log Mean can be used as a proxy for pore-size distribution changes is valid in the Three Forks Formation. While the NMR total porosity from T2 remains relatively consistent in the three benches of the Three Forks, there are significant changes in the T2 Log Mean from bench to bench. There is a positive correlation between changes in T2 Log Mean and average pore size measured on SEM samples. Study of a “type” well, QEP’s Ernie 7-2-11 BHD (Sec. 11, T149N, R95W, McKenzie County), shows that the 1- to 5-micron pores in the first bench have a T2 Log Mean relaxation time of 10.2 msec, whereas the 500- to 800-nanometer pores in the chlorite-filled intercrystalline pores in the second bench have a T2 Log Mean of 4.96 msec. This compares with a T2 Log Mean of 2.86 msec in 3rd bench where pores average just 200 nanometers in size. These data suggest that the NMR log is a useful tool for quantifying average pore size in the various benches of the Three Forks Formation.

Tight Jurassic Carbonate Reservoir Characterization and Fluid Typing Identification by Integrating Magnetic Resonance, Elemental Spectroscopy and Micro-Resistivity Image Data in Umm Ross Field, West Kuwait, Case Study

2021 ◽  
Author(s):  
Said Beshry Mohamed ◽  
Sherif Ali ◽  
Mahmoud Fawzy Fahmy ◽  
Fawaz Al-Saqran
Keyword(s):  
Magnetic Resonance ◽  
Reservoir Characterization ◽  
Clay Content ◽  
Effective Porosity ◽  
Carbonate Reservoir ◽  
High Resistivity ◽  
Permeability Index ◽  
Rock Quality ◽  
Porosity And Permeability ◽  
Bulk Volume

Abstract The Middle Marrat reservoir of Jurassic age is a tight carbonate reservoir with vertical and horizontal heterogeneous properties. The variation in lithology, vertical and horizontal facies distribution lead to complicated reservoir characterization which lead to unexpected production behavior between wells in the same reservoir. Marrat reservoir characterization by conventional logging tools is a challenging task because of its low clay content and high-resistivity responses. The low clay content in Marrat reservoirs gives low gamma ray counts, which makes reservoir layer identification difficult. Additionally, high resistivity responses in the pay zones, coupled with the tight layering make production sweet spot identification challenging. To overcome these challenges, integration of data from advanced logging tools like Sidewall Magnetic Resonance (SMR), Geochemical Spectroscopy Tool (GST) and Electrical Borehole Image (EBI) supplied a definitive reservoir characterization and fluid typing of this Tight Jurassic Carbonate (Marrat formation). The Sidewall Magnetic resonance (SMR) tool multi wait time enabled T2 polarization to differentiate between moveable water and hydrocarbons. After acquisition, the standard deliverables were porosity, the effective porosity ratio, and the permeability index to evaluate the rock qualities. Porosity was divided into clay-bound water (CBW), bulk-volume irreducible (BVI) and bulk-volume moveable (BVM). Rock quality was interpreted and classified based on effective porosity and permeability index ratios. The ratio where a steeper gradient was interpreted as high flow zones, a gentle gradient as low flow zones, and a flat gradient was considered as tight baffle zones. SMR logging proved to be essential for the proper reservoir characterization and to support critical decisions on well completion design. Fundamental rock quality and permeability profile were supplied by SMR. Oil saturation was identified by applying 2D-NMR methods, T1/T2 vs. T2 and Diffusion vs. T2 maps in a challenging oil-based mud environment. The Electrical Borehole imaging (EBI) was used to identify fracture types and establish fracture density. Additionally, the impact of fractures to enhance porosity and permeability was possible. The Geochemical Spectroscopy Tool (GST) for the precise determination of formation chemistry, mineralogy, and lithology, as well as the identification of total organic carbon (TOC). The integration of the EBI, GST and SMR datasets provided sweet spots identification and perforation interval selection candidates, which the producer used to bring wells onto production.

Enhanced and Rock Typing-Based Reservoir Characterization of the Palaeocene Harash Carbonate Reservoir-Zelten Field-Sirte Basin-Libya

2021 ◽  
Author(s):  
Mohamed Masoud ◽  
W. Scott Meddaugh ◽  
Masoud Eljaroshi ◽  
Khaled Elghanduri
Keyword(s):  
Rock Type ◽  
Carbonate Reservoir ◽  
Classification Model ◽  
Reservoir Rocks ◽  
The Core ◽  
Core Samples ◽  
Rock Types ◽  
Rock Typing ◽  
Open Hole ◽  
Type Classification

Abstract The Harash Formation was previously known as the Ruaga A and is considered to be one of the most productive reservoirs in the Zelten field in terms of reservoir quality, areal extent, and hydrocarbon quantity. To date, nearly 70 wells were drilled targeting the Harash reservoir. A few wells initially naturally produced but most had to be stimulated which reflected the field drilling and development plan. The Harash reservoir rock typing identification was essential in understanding the reservoir geology implementation of reservoir development drilling program, the construction of representative reservoir models, hydrocarbons volumetric calculations, and historical pressure-production matching in the flow modelling processes. The objectives of this study are to predict the permeability at un-cored wells and unsampled locations, to classify the reservoir rocks into main rock typing, and to build robust reservoir properties models in which static petrophysical properties and fluid properties are assigned for identified rock type and assessed the existed vertical and lateral heterogeneity within the Palaeocene Harash carbonate reservoir. Initially, an objective-based workflow was developed by generating a training dataset from open hole logs and core samples which were conventionally and specially analyzed of six wells. The developed dataset was used to predict permeability at cored wells through a K-mod model that applies Neural Network Analysis (NNA) and Declustring (DC) algorithms to generate representative permeability and electro-facies. Equal statistical weights were given to log responses without analytical supervision taking into account the significant log response variations. The core data was grouped on petrophysical basis to compute pore throat size aiming at deriving and enlarging the interpretation process from the core to log domain using Indexation and Probabilities of Self-Organized Maps (IPSOM) classification model to develop a reliable representation of rock type classification at the well scale. Permeability and rock typing derived from the open-hole logs and core samples analysis are the main K-mod and IPSOM classification model outputs. The results were propagated to more than 70 un-cored wells. Rock typing techniques were also conducted to classify the Harash reservoir rocks in a consistent manner. Depositional rock typing using a stratigraphic modified Lorenz plot and electro-facies suggest three different rock types that are probably linked to three flow zones. The defined rock types are dominated by specifc reservoir parameters. Electro-facies enables subdivision of the formation into petrophysical groups in which properties were assigned to and were characterized by dynamic behavior and the rock-fluid interaction. Capillary pressure and relative permeability data proved the complexity in rock capillarity. Subsequently, Swc is really rock typing dependent. The use of a consistent representative petrophysical rock type classification led to a significant improvement of geological and flow models.

Objective-Driven Solid-Surface-Roughness Characterization for Enhanced Nuclear-Magnetic-Resonance Petrophysics

SPE Journal ◽  
2021 ◽  
pp. 1-20
Author(s):  
Shouxiang Mark Ma ◽  
Gabriela Singer ◽  
Songhua Chen ◽  
Mahmoud Eid
Keyword(s):  
Nuclear Magnetic Resonance ◽  
Surface Roughness ◽  
Magnetic Resonance ◽  
Pore Size ◽  
Solid Surface ◽  
Micro Ct ◽  
Roughness Effects ◽  
Formation Evaluation ◽  
Petrophysical Parameters ◽  
Rock Types

Summary Typically, smooth solid surfaces of reservoir rocks are assumed in formation evaluation, such as nuclear-magnetic-resonance (NMR) petrophysics and reservoir-wettability characterization through contact-angle measurements. Measuring the degree of surface roughness (R), or smoothness, and evaluating its effects on formation evaluation are topics of much research. In this paper, we primarily focus on details in characterizing solid-surface roughness and its applications in NMR pore-sizeanalysis. R can be measured by contact techniques and noncontact techniques, such as stylus profilometer, atomic-force microscopy, and different kinds of optical measurements. Each technique has different sensitivities, measurement artifacts, resolutions, and field of view (FOV). Intuitively, although a finer resolution measurement provides the closest account of all surface details, the correspondingly small FOV might compromise the representativeness of the measurement, which is particularly challenging for charactering heterogeneous samples such as carbonates. To balance the FOV and measurement representativeness, and to minimize artifacts, laser scanner confocal microscopy (LSCM) is selected in this study. Results for the more than 27 rock samples tested indicate that rocks of similar rock types have similar R-values. Grainy limestones have relatively higher R-values compared with dolostones, consistent with the dolostone’s crystallization surface features. Muddy limestones have smoother surfaces, resulting in the lowest R-values among the rocks studied. For sandstones, R varies with clay types and content. For rocks containing two distinct minerals, two R-values are observed from the R profiles, which for these rock types justifies the use of two NMR surface relaxivity (ρ2) parameters for determining the pore-size distribution (PSD) from the NMR T2distribution. The novelty here is the integration of LSCM and NMR to obtain an NMR PSD relevant for permeability, capillary pressure, and other petrophysical parameters. Typically, ρ2 is calibrated using the total surface area from Brunauer-Emmett-Teller (BET; Brunauer et al. 1938) gas adsorption, but this underestimates the NMR pore size because of surface-roughness effects. In our novel approach, we use R measured from LSCM to correct ρ2 for surface-roughness effects, and thereby obtain the NMR pore size more relevant for permeability and other petrophysical parameters. We then compare the roughness-corrected NMR PSD against pore size from microcomputed tomography (micro-CT) scanning (which is roughness independent). The good agreement between roughness-corrected NMR and micro-CT pore sizes in the micropore region validates our new technique, and highlights the importance of surface-roughness characterization in NMR petrophysics.

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