Free Fluid Index Research Articles

Investigation of cross-scale characterization of porous structure and fluid index in bituminous coal via microwave-LN2 freeze-thaw cycles

Microwave-LN2 cyclic processing (MLCP) is a clean and high-efficiency anhydrous fracturing technology. The change in the porous structure of coal after freeze-thaw cycles significantly affects development efficiency of coalbed methane (CBM) in low porosity and permeability reservoirs, while there is a lack of in-depth macro-meso-micro studies. The damage mechanism of coal under microwave-LN2 cold and thermal shock and the evolution of pore fluid reservoir space is based on cross-scale pore characterisation. This paper evaluates the multi-scale porous structure variations of coal before and after MLCP was assessed by hydrogen nuclear magnetic resonance (1H NNR) and field emission scanning electron microscopy (FE-SEM). The evolutionary trends in coal pore fluid fugacity space under freeze-thaw cycles was indirectly characterised by T1-T2 spectra. Additionally, utilizing T2 distribution, peak area and pore throat changes reflect the evolution trend of coal pore space. The results indicate that as the cycles increased, the coal free water and total fluid reservoir space gradually expanded beyond the cycle threshold (n > 10), the free-fluid index rose to 25.68 %, and the free fluid saturation increased by 20.39 %. Additionally, the NMR permeability of the coal increased by 98.37–1471.65 %, and the pore throat distribution increased by 28.05 %. Comprehensive analysis showed that as the cycles progressed, the free water space in the pore space increased significantly, the proportion of bound water gradually decreased, and the internal pores and fluid space of the coal were improved. This study provides fundamental support for multidimensional evaluation of the porous structure of microwave-LN2 freeze-thaw cycles.

Evolution and controls of high reservoir quality in Oligocene sandstones from moderate to deep burial, Nanpu Sag, Bohai Bay Basin, China

The Oligocene sandstones characterized by highly variable reservoir quality are the main hydrocarbon exploration and development targets in the Nanpu Sag, Bohai Bay Basin, China. In this study, the evolution and controls of reservoir quality in Oligocene sandstones from moderate to deep burial were investigated using petrographic and petrological data. The results show that the Oligocene sandstones are mostly fine-to coarse-grained, subangular to subrounded roundness, moderately sorted feldspathic litharenites and lithic arkoses with an average Q/F/R distribution of 48.4: 29.1: 22.5. Three anomalously high porosity/permeability zones (AHPZs, hereinafter named AHPZ-I, AHPZ-II, and AHPZ-III, respectively) are developed at depth ranges of 2300–3100 m, 3200–3550 m, and 3700–4200 m, respectively. Notably, the three zones are featured by distinctly different pore types: mainly primary pores in AHPZ-I; pore combination (average primary pore volume > average secondary pore volume) in AHPZ-II; primary pores with a few microfractures in AHPZ-III. The pore-throat sizes controlling permeability in anomalously high porosity sandstones (AHPS) decrease steadily from AHPZ-I to AHPZ-III-1 and then increase significantly at AHPZ-III-2. The AHPS reservoirs are characterized by low displacement pressure, large pore throat and mercury intrusion saturation, and high free fluid index (FFI) and reservoir quality index (RQI).Compaction greatly degraded the reservoir quality of Oligocene sandstones; carbonate cementation further restricts the formation of high-quality reservoirs. The sandstones with low content (<10 %) of carbonate cements tend to have larger primary porosity and secondary porosity, hence a larger RQI. The formation of AHPZ-I and AHPZ-II is attributed to higher content of rigid particle components, lower carbonate cements, and strong dissolution. Moreover, good sorting, responsible for a higher original porosity, also plays a positive role in the cause of AHPZ-I. The coarse-grained particles and early petroleum emplacement are the keys to the preservation of primary porosity in AHPZ-III. The petroleum emplacement effectively inhibits the feldspar dissolution and kaolinite precipitation in the deeply buried sandstones with depths larger than 4000 m. In addition, the generation of crushed microfractures in coarse grains leads to relatively low porosity and high permeability.

Clustering of facies in tight carbonates using machine learning

Machine learning clustering methods offer the potential for recognition and separation of facies based on core or well-log data. This is a particular problem for carbonate rocks because diagenesis produces a wide range of rock microstructures and transport properties. In this work we use a large database of high quality poroperm, electrical, mercury injection capillary pressure and nuclear magnetic resonance spectroscopy measurements (307 core samples), representing 5 stratigraphically defined facies, as well as well log data to examine facies-recognition abilities using 8 different machine learning clustering approaches and a redundancy of 10 to ensure statistically valid results, resulting in a total of over 990 clustering runs. For a 3 cluster problem, we find that the Expectation Maximisation (92.57% success) and two types of Kmeans approaches (89.60% and 91.09%) provide the best methods. Further testing using the best of these shows that the quality of the input parameter (attribute) matters more than the number of attributes used, with the power of attributes in decreasing order being porosity, cementation exponent, permeability, pore throat diameter and free fluid index, implying that some attributes can degrade clustering performance. Further tests show that there should be at least as many attributes as clusters, in which case the machine learning can be left to choose the final number of clusters, providing the best performance in this work (69.35% success for a five cluster problem), otherwise it is best to constrain the cluster number by supervision. Application of the results from the previous testing to a mixed carbonate tight carbonate well from the Butmah formation shows satisfactory determination of 4 petrofacies by clustering (up to 91.65%) when compared to petrofacies determined manually. However, the greater challenge of clustering 9 reservoir quality classes defined using a ternary petrofacies approach did not provide a successful result (<38% success rate).

Synthesizing Nuclear Magnetic Resonance (NMR) Outputs for Clastic Rocks Using Machine Learning Methods, Examples from North West Shelf and Perth Basin, Western Australia

A nuclear magnetic resonance (NMR) logging tool can provide important rock and fluid properties that are necessary for a reliable reservoir evaluation. Pore size distribution based on T2 relaxation time and resulting permeability are among those parameters that cannot be provided by conventional logging tools. For wells drilled before the 1990s and for many recent wells there is no NMR data available due to the tool availability and the logging cost, respectively. This study used a large database of combinable magnetic resonance (CMR) to assess the performance of several well-known machine learning (ML) methods to generate some of the NMR tool’s outputs for clastic rocks using typical well-logs as inputs. NMR tool’s outputs, such as clay bound water (CBW), irreducible pore fluid (known as bulk volume irreducible, BVI), producible fluid (known as the free fluid index, FFI), logarithmic mean of T2 relaxation time (T2LM), irreducible water saturation (Swirr), and permeability from Coates and SDR models were generated in this study. The well logs were collected from 14 wells of Western Australia (WA) within 3 offshore basins. About 80% of the data points were used for training and validation purposes and 20% of the whole data was kept as a blind set with no involvement in the training process to check the validity of the ML methods. The comparison of results shows that the Adaptive Boosting, known as AdaBoost model, has given the most impressive performance to predict CBW, FFI, permeability, T2LM, and SWirr for the blind set with R2 more than 0.9. The accuracy of the ML model for the blind dataset suggests that the approach can be used to generate NMR tool outputs with high accuracy.

Predicting the flow zone indicator of carbonate reservoirs using NMR echo transforms, and routine open-hole log measurements: Insights from a field case study spanning extreme micro-structure properties

Predicting the flow zone indicator is essential for identifying the hydraulic flow units of hydrocarbon reservoirs. Delineation of hydraulic flow units is crucial for mapping petrophysical and rock mechanical properties. Precise prediction of the flow zone indicator (FZI) of carbonate rocks using well log measurements in un-cored intervals is still a daunting challenge for petrophysicists. This study presents a data mining methodology for predicting the rock FZI using NMR echo transforms, and conventional open-hole log measurements. The methodology is applied on a carbonate reservoir with extreme microstructure properties, from an oil “M” field characterized by a relatively high-permeability with a median of approximately 167 mD, and a maximum of 3480 mD. The reservoir from the M field features detritic, or vuggy structure, covering a wide range of rock fabrics varying from microcrystalline mudstones to coarse-grained grainstones. Porosity has a median of approximately 22%. Dimensional analysis and regression analysis are applied for the derivation of four transforms that appear to capture approximately 80% of the FZI variance. These four transforms are formulated using the geometric mean of the transverse NMR relaxation time (T2lm), the ratio of the free fluid index (FFI) to the bulk volume irreducible (BVI), the bulk density, the sonic compressional travel time, the true resistivity, the photo-electric absorption, and the effective porosity. Non-linear regression models have been developed for predicting the FZI using the derived transforms, for the carbonate reservoir from the M field. The average relative error for the estimated FZI values is approximately 52%. The same transforms are used as input for training a developed general regression neural network (GRNN), built for the purpose of predicting rock FZI. The constructed GRNN predicts FZI with a notable precision. The average absolute relative error on FZI for the training set is approximately 3.1%. The average absolute relative error on FZI for the blind testing set is approximately 22.0 %. The data mining approach presented in this study appears to suggest that (i) the relationship between the flow zone indicator and open-hole log attributes is highly non-linear, (ii) the FZI is highly affected by parameters that reflect rock texture, rock micro-structure geometry, and diagenetic alterations, and (iii) the derived transforms provide a means for further enhancement of the flow zone indicator prediction in carbonate reservoirs.

Improved grey correlation theory to quantitatively characterize the effect of pore parameters on compressive strength of cement Pisha sandstone

In order to objectively characterize the correlation degree of the influence of different pore parameters of cement solidified soft rock on compressive strength. The initial data of pore parameters and compressive strength are normalized by five different dimensionless methods, and the correlation degree of each parameter is calculated. Based on the mode theory and spearman theory, an improved grey correlation calculation model is established to evaluate the correlation degree of pore parameters. The results show that the correlation degree between pore parameters and compressive strength of cement Pisha sandstone is in the following order: >0~0.1μm aperture ratio, bound fluid index, >1μm aperture ratio, free fluid index, T2 spectrum area, porosity and >0.1~1μm aperture ratio. The spearman rank correlation coefficients of sample C4 were 0.964, 0.536, 0.893 and 0.964 respectively; The spearman rank correlation coefficients of sample C7 were 0.964, 0.607, 0.964 and 0.893 respectively. It can be seen that “ Range Analysis “ is the best normalization method among the five dimensionless methods, and its evaluation results are most in line with the actual situation. This study provides a new mathematical method for quantitatively characterizing the grey correlation effect of pore parameters of cement-based materials on compressive strength.

Geochemical Properties and Pore Structure Control on Oil Extraction of Shale

Abstract Despite geochemical properties and pore structures for shale oil extraction, the interplay among shale chemistry, pore network, and hydrocarbon movability still is an open question. Here, by using hybrid experimental methods, including backscatter scanning electron microscopy, X-ray diffraction, adsorption/desorption isotherm, and nuclear magnetic resonance, we provide a general characteristic of geochemistry and pore structures of Chang 7 (C7) shale in Ordos basin and figure out how these properties impact the shale oil extraction. Our results confirmed that the C7 shale in Ordos basin could be divided into three types based on the mineral components with various pore structures, and the proportion of the pores that radius below 4.8 nm (from adsorption branch) or 3.8 nm (from desorption branch) play a dominant role in the determination of pore size distributions. The kerogen index that is derived from maceral types was the most significant geochemical indicator; high kerogen index was corresponding to large pore volumes and surface areas, but low pore diameters. We identify the pore structure mechanism—mesopores predominantly or micropores abundantly (increase free fluid index) and absence of inorganic or organic pores (decrease free fluid index)—responsible for the oil extraction capability and show that the unmovable fluid stained in the voids would lead to the slow rate decay of the curves, which caused the nonsignal disturbance. Our results demonstrate the powerful control of maceral components and pore diameters on shale oil extraction and show the markedly different flow behavior of various types of shale.

The rock-fabric/petrophysical characteristics and classification of the micropores hosted between the calcite and dolomite crystals

For the substantial hydrocarbon potential and academic significance, focus of interest has been directed towards the microporous carbonate. Compared with the documented shallow burial microporous carbonate, carbonate with a depth deeper than 6000 m present, of course, different characteristics due to the long-term influences of the strong cementation and compaction. With the deepening of exploration, it is therefore essential to improve the understanding about the deep burial microporous carbonate. In this paper, an integrated petrographic and petrophysical approach, which combines thin section, high-resolution field emission scanning electron microscopy (FESEM) observations, and nuclear magnetic resonance (NMR) measurements, is chosen to study the deep to ultradeep carbonate in the Shunnan area, Tarim Basin, NW China.Results show that all the studied carbonate samples consist entirely of micropores with a radius less than 10 μm, belonging to the strictly microporous carbonate. These micropores exist between the calcite and dolomite microcrystals. To reliably calculate the permeability based on NMR data, a newly introduced factor P aiming to adjust the T2 cut-off value derived from the relaxation curve is applied to enhance the Coates model. Values of P are found to correlate well with the FFI (free fluid index) of the bioclastic and bioclasts-free detrital limestones through different quantitative relationships, respectively. Permeabilities calculated from the modified Coates model are in good agreements with those measured by the pulse-decay method (R2 = 0.93, 0.67). Considering the existing classifications of pore systems are not applicable to the peculiar intercrystalline micropores within the deep burial microporous carbonate, a noval classification scheme is thus explored by integrating the rock-fabric and petrophysical properties. Micropores hosted within the subhedral to anhedral microcrystals with distinct boundaries are the main reserving space of the microbial lime-/dolostone, which lead to relatively higher porosities (averaging 3.41%) than the detrital limestone (1.99%) and dolostone (2.47%), and an identical right-skewed trimodal NMR T2 distribution. Micropores related with the coalescent polyhedral to anhedral microcrystals, that are always glued together to form fusing boundaries, are mainly located within the micrite matrix and allochem of the detrital limestone. Certain relationships among porosity, permeability and FFI/BVI also exist for the bioclastic and bioclasts-free detrital limestones, respectively. Micropores within the dolostone exist between the rhombic dolomite crystals. This proposed classification of micropores comprehensively reflects the depositional, diagenetic textures and physical properties of the deep burial microporous carbonate. The particularity of microbial lime-/dolostone is highlighted.

Influence of net confining stress on NMR T2 distribution and two-phase relative permeability

Relative permeability stress sensitivity studies reported in literature do not have a common conclusion with regards to end point saturations and their respective relative permeabilities. Moreover, there is lack of experimental results on stress sensitivity of pore fluid distribution, which is a key parameter for the behavior of relative permeability curves. This study extended core homogeneity to include similar porosity, permeability and NMR T2 distribution as well as examined NMR T2 distribution behavior with stress on artificial sandstone cores and the results used in explaining relative permeability stress sensitivity under net confining stresses of 5, 15 and 25 MPa. The effect of stress on displacement efficiency was also investigated. The bulk volume irreducible (BVI), which is the fraction of the bulk volume containing irreducible water, generally increased with stress. Meanwhile the free fluid index (FFI), which is the fraction of the bilk volume responsible for fluid flow, decreased with increased stress. NMR irreducible water saturation and irreducible water saturation obtained from relative permeability experiments both increased with stress. Irreducible water saturation was strongly related to the behavior BVI stress sensitivity. Residual oil saturation increased with increase in stress as a result of reductions in FFI pore volume. End-point oil relative permeability had a significant decrement with stress while water end-point relative permeability had a negligible decrement. The significant reduction in end-point oil relative permeability was due to reductions in pore radius evident in a corresponding reduction in FFI. Displacement efficiency decreased with increased stress indicating lower oil recovery on microscopic scale but end-point mobility ratio increased as stress increased. Relative permeability stress sensitivity could be tied to changes in BVI and FFI of NMR T2 distribution when changes in stress occur in petroleum reservoirs.

Application of nuclear magnetic resonance permeability models in tight reservoirs

AbstractTight reservoir permeability with values ranging from a few nD–0.1 mD is a challenging parameter to measure. Since the 1970s, many correlations were applied to estimate the permeability of tight formations using the nuclear magnetic resonance (NMR) technique. Due to increasing interest in tight reservoir recovery, each year many papers are published on the Timur‐Coates and Kenyon models and their modification on estimating the NMR permeability of tight reservoirs. It brings up the question of which is the most accurate, reliable, and feasible model to be used for predicting tight NMR permeability.The first part of this paper is dedicated to introducing the existing models for NMR‐based estimates of tight reservoir permeability. The second part compares these models by applying them on tight reservoirs from North America, Asia, and Europe. NMR experiments were conducted on 150 cores. NMR T2 relaxation times were measured and effective and total porosities, the geometric mean of relaxation time (T2gm), irreducible bulk volume (BVI), and free fluid index (FFI) were calculated. For validation of the models, the cross plots of NMR permeability versus the Klinkenberg gas permeability are presented. Comparison of the model is based on the calculated standard error of these two independently measured permeabilities.This paper is beneficial in understanding existing tight reservoir NMR permeability models. The results can be used as a guide for choosing the best NMR permeability estimation model for tight reservoirs data.

Hydrocarbon viability prediction of some selected reservoirs in Osland Oil and gas field, Offshore Niger Delta, Nigeria

Abstract An alternative approach involving the use of modified expressions for the free fluid index (FFI) permeability (K), reservoir quality index (RQI) and flow zone indicator (FZI), was used to predict the viability of hydrocarbon in some selected reservoirs. The aim of this work is to predict flow units, transmissibility and primary recovery through porosity (Ф) derived from wire-line logs. In the absence of core data, Ф values derived from the density log (RHOB) were optimised herein. Alternative expressions for the FFI, K, RQI, and FZI were suggested. A simplified approach with the use of only porosity dependent expressions for these parameters (FFI, K RQI, and FZI) that lies within the scope of the study was used for the evaluation of the reservoirs. Quick-look models for the prediction of RQI an FZI based on these the redefined equations were presented. Drudgery and computational errors that may come with the use of a range of other dependent parameters [irreducible water saturation (Swirr), formation factor (F), tortuosity factor (a) and cementation exponent (m)] were avoided. The reservoir, in well D1, is about 90 ft (27 m) thick, with the upper 30 ft (9 m) occupied by gas, the next 28 ft (8.5 m) is filled with oil and the remaining 32 ft (9.8 m) is water filled. The reservoir, in well D2, is about 110 ft (33.5 m) thick and it is oil saturated. Within D1 reservoir, average Ф, FFI, K, RQI, and FFI are 0.2, 0.18, 1256mD, 2.5 μm and 10.1 μm respectively. Within D2 reservoir, average Ф, FFI, K, RQI, and FFI are 0.25, 0.23, 5166mD, 4.5 μm and 13.5 μm respectively. Significant transmissibility and good rates of hydrocarbons recoveries are anticipated within the evaluated reservoirs.

Fractal analysis of tight shaly sandstones using nuclear magnetic resonance measurements

Assessing quantitatively the microscopic pore structures of porous rocks, including irregularities of pore shapes and pore size distributions, is becoming one of the most challenging efforts. Nuclear magnetic resonance (NMR) measurements were used to provide insights into the pore geometry (pore size and shape) and pore connectivity of the Chang 7 tight shaly sandstones (in situ permeability <0.1 md) in Ordos basin. The incremental transverse relaxation time (T2) distributions for the 100% brine-saturated samples display unimodal and bimodal behaviors, presenting a geometrical arrangement composed of small to large pore size domains. The NMR parameters such as bulk volume irreducible (BVI) (capillary and clay-bound water), free fluid index (FFI) (movable water), the value of T2 separating the BVI from FFI, the amplitude weighted mean on a logarithmic scale (T2gm), and the value of T2 that shows the highest frequency on the T2 spectrum (T2peak) for each sample were determined. Then the fractal theory was adopted to quantitatively express the complexity and heterogeneity of the sandstones. The results show that only minor primary intergranular porosity remains, and variable amounts of micropores and secondary intragranular porosity with poor connectivity occur in the Chang 7 tight shaly sandstones. Assuming spherical pores, a new model to calculate the fractal dimension of pore structure from the NMR T2 distributions is proposed. The fractal dimensions of all the samples are calculated, and the accuracy of the proposed model is verified by the regression coefficients. The microscopic pore structures are heterogeneous in these tight sandstones according to the high value of fractal dimensions. Micropores are the primary causes of heterogeneity in tight sandstones, and samples with unimodal T2 distribution behaviors and high content of short components have the highest fractal dimension and heterogeneity. The calculated fractal dimension is strongly correlated with T2peak and T2gm; therefore, the fractal model proposed in this study can be used to calculate the fractal dimensions and evaluate the heterogeneities of the porous rocks satisfactorily. The fractal model proposed in this study helps to quantitatively assess the pore structures of tight sandstones using NMR measurements.

Tight Reservoir Properties Derived by Nuclear Magnetic Resonance, Mercury Porosimetry and Computed Microtomography Laboratory Techniques. Case Study of Palaeozoic Clastic Rocks

Results of the nuclear magnetic resonance (NMR) investigations, mercury porosimetry measurements (MP) and computed microtomography (micro-CT), applied to the tight Palaeozoic rocks from the depths lower than 3000 m, were presented to estimate their reservoir potential. NMR signal analysis and interpretation were performed. Based on NMR driven models, permeability and Free Fluid Index were calculated for data sets divided into homogeneous clusters. Computerized mercury porosimetry results visualization and processing provided useful information, as the automatically determined Swanson parameter is correlated with petrophysical properties of rocks. Micro-CT enriched the image of porous space in qualitative and quantitative ways. Homogeneity of pore space structure was discussed using micro-CT approach. Integration of the results in the frame of reservoir parameters from standard laboratory methods and the modern ones resulted in the improvement of methodology for determining the old, deep-seated, hard sedimentary rocks reservoir potential.

The influence of fracture cements in tight Paleogene saline lacustrine carbonate reservoirs, western Qaidam Basin, northwest China

Paleogene saline lacustrine carbonate rocks are important fractured reservoirs in the western Qaidam Basin. Core data show that most fractures are small, steeply dipping faults; bedding-plane slip faults; and subvertical opening-mode fractures. Other fractures are diagenetic in origin. Fracture occurrence and abundance patterns are controlled by lithology, bed thickness, and proximity to larger faults. Fractures are generally filled with calcite, gypsum, or glauberite (Na2Ca[SO4]2); the degree of fracture filling determines the effectiveness of fractures as fluid conduits and the distribution of high-quality reservoirs. Open fractures not only provide the main pathways for fluid flow, but also enhance the free fluid index and the free fluid saturation measured by nuclear magnetic resonance and determine the potential production rates of tight carbonate reservoirs. The open fractures are parallel to and occur near faults, and many do not coincide with the present-day direction of the maximum horizontal compressive stress.

NMR Measurements and Determination of Rock Petrophysical Properties and Lithofacies (Naricual Formation, Eastern Venezuelan Basin)

This research studies the petrophysical properties and lithofacies of the Naricual Formation (Venezuela) through the nuclear-magnetic resonance measurements of 12 lithologically complex sandstone core plugs from well FGB-1. Bulk volume irreducible index, free fluid index, critical water saturation, and other properties were determined. NMR estimates of permeability were derived from T2 distributions using a modified Timur-Coates Free Fluid model. The results showed that the values of the novel FFI0.9/BVI ratio covered five ranges depending on the lithofacies of each rock in the Naricual Formation. Last, we conclude that NMR technology is an effective tool for the determination of rock facies.

Wettability effects in a sandstone reservoir and outcrop cores from NMR relaxation time distributions

An extensive literature has emerged on the use of nuclear magnetic resonance (NMR) relaxation methods for the determination of various petrophysical properties such as porosity, permeability, initial water saturation and free fluid index. Although observations were first made in the 1950s, relatively few papers have appeared, which use NMR methods to determine the wettability state of a crude oil/brine/rock (COBR) system. Differences in the relaxation time distributions (for both T 1 and T 2) at the various saturation stages in the Amott test cycle provide both qualitative and quantitative information on the wettability state in sandstone samples. Two particularly convenient ways of plotting our results are proposed based on: (a) the arithmetic mean relaxation time differences given by Δ T 1=〈 T 1 at S or〉−〈 T 1 at S wi〉 and Δ T 2=〈 T 2 at S or〉−〈 T 2 at S wi〉; and, (b) the arithmetic mean relaxation time ratios given by 〈 T 1 at S wi〉/〈 T 1 at S or〉 and 〈 T 2 at S wi〉/〈 T 2 at S or〉. In each case, these quantities are plotted against the Amott–Harvey (AH) index and good linear relationships are found. We propose measuring the relaxation times at the S wi and S or stages of a flood cycle and plotting the results in this way as the basis of quantitative NMR-based tests to characterise rock wettability. We find that both the T 1 and T 2 relaxation time data correlate with the wettability condition of the system although the T 1 plots give rather better wettability indicators. This implies that both relaxation times carry broadly similar information on wettability. Although the correlations are somewhat weaker for T 2, there is some potential for indicating wettability alteration using T 2 distributions obtained from downhole NMR logging tools. Comparing the corresponding T 1 and T 2 cumulative curves before and after ageing indicates that wetting alteration first takes place in the larger pores, while the smaller pores appear to remain water-wet. The number of wetting altered pores (from water-wet→weakly water-wet→oil-wet) increases with the increase in ageing time, indicating that the samples studied here are showing mixed wettability behaviour on ageing.

5565775 Producible fluid volumes in porous media determined by pulsed field gradient nuclear magnetic resonance

The present invention is a method to determine the bound and free fluid index of fluids in porous media by pulsed field gradient (PFG) NMR diffusion measurements. The PFG NMR signal is evaluated using a two-fluid model that describes the self diffusion coefficients for the fluid fractions with low and high translational mobilities.

Preparation of Specific‐Yield Logs for Clastic Bedrock Aquifers

AbstractSpecific yield is the principal aquifer characteristic needed to estimate the volume of recoverable ground water in storage in an aquifer. Determination of specific yield can be difficult and costly, particularly in deep, confined aquifers where core drilling and core analyses may be needed to define specific yield. A method has been developed for preparation of specific‐yield geophysical logs that could greatly ease the determination of specific yields in such aquifers.Three geophysical logs that were investigated as potential indicators of specific yield were the free fluid index log, the effective‐porosity log, and the apparent grain‐density log. The free fluid index log did not accurately represent conditions at the test site in central Colorado and may not be suitable for application in other shallow and permeable aquifers. The effective‐porosity and apparent grain‐density logs were each used in least‐squares linear regressions to correlate log response to specific yield measured in core samples. The resulting regression equations have coefficients of correlation (R) of 0.84 and 0.90, and were used to successfully prepare specific‐yield logs from the effective‐porosity and apparent grain‐density logs.

NML-The Hope for Production Prediction

The nuclear magnetism log (NML) has recently been upgraded to a workable and reasonably trouble-free service. Although the first NML was run commercially in 1960 by Perforating Guns Atlas Corp., the service did not become routinely adequate until 1987. The NML has been one of the great hopes for significant improvement in log interpretation and should now provide the next significant improvement in log interpretation. The NML instrument measures the nuclear magnetism of protons. The proton is a particle identical to the nucleus of the hydrogen atom. The proton is like a magnet; when placed in a magnetic field, it tends to align with the magnetic field like a compass needle. The NML instrument in its simplest form has a large coil that produces a magnetic field when electrical current is passed through this coil. The protons in the formations around the wellbore are aligned by this magnetic field. The borehole (mud) is ''doped'' with something like magnetite to eliminate the borehole influence. When the magnetic field is released by stopping current flow in the coil, the protons tend to realign with the earth's magnetic field. During the process of realigning, the protons give back the energy that it tookmore » to align them. This energy induces a signal in the same coil used to create the magnetic field. The process is very inefficient.« less

Statistical Analysis of Correlation of Porosity and Permeability Determinations from Well Cuttings Using a Portable pNMR Apparatus with Conventional Core Analysis and Wireline Log Readings: ABSTRACT

The porosity-permeability (P-K) analyzer is a field-portable device that uses the principle of pulsed nuclear magnetic resonance to determine the content of hydrogen nuclei present in the free and bound water in rock samples. Using a simple dual-water model, these values may be used to calculate total porosity, free fluid index, and permeability index. The principle of measurement is such as to require relatively small sample volumes and reliable results can be obtained from well-cuttings samples or 3-mm diameter core plugs. Results from the P-K analyzer are responsive to total fluid-filled pore space in the rock, although it is possible to distinguish free, i.e., movable, fluid from bound fluid, i.e., at grain boundaries or within restricted pores and in argillaceous rocks. The P-K response is entirely independent of formation lithology, mineralogy, or salinity of pore waters and is not appreciably affected by the presence of light oils. The presence of free or dissolved gases in the sample will have a significant effect on response. However, samples are brine flushed and aspirated in preparation for analysis in order to remove this effect. We see, from these differences, that results from the P-K method cannot be expected to show a direct one-to-one correlation with those from conventional core analysis or the wireline density or neutron logging tools. A statistical analysis is presented using data from each of the analytical methods and types and conditions of sample. A strong correlation is demonstrated both visually and statistically, thereby providing verification of the P-K method and facilitating its use alongside data previously obtained by more conventional methods. End_of_Article - Last_Page 673------------