Showing papers on "Effective porosity published in 2004"

Estimation of effective porosity using geostatistics and multiattribute transforms: A case study

Abstract: The middle Eocene Kalol Formation in the north Cambay Basin of India is producing hydrocarbons in commercial quantity from a series of thin clastic reservoirs. These reservoirs are sandwiched between coal and shale layers, and are discrete in nature. The Kalol Formation has been divided into eleven units (K‐I to K‐XI) from top to bottom. Multipay sands of the K‐IX unit 2–8 m thick are the main hydrocarbon producers in the study area. Apart from their discrete nature, these sands exhibit lithological variation, which affects the porosity distribution. Low‐porosity zones are found devoid of hydrocarbons. In the available 3D seismic data, these sands are not resolved and generate a composite detectable seismic response, making reservoir characterization through seismic attributes impossible. After proper well‐to‐seismic tie, the major stratigraphic markers were tracked in the 3D seismic data volume for structural mapping and carrying out attribute analysis. The 3D seismic volume was inverted to obtain an aco...

Origin and petrophysics of dolostone pore space

Abstract: The common claim that dolomitization creates 12% porosity is based on the mole-for-mole replacement equation. However, in the past 50 years, data have been collected demonstrating that dolomitization does not create porosity. Instead, dolostones inherit the porosity and fabric of the precursor limestone, and porosity is reduced by overdolomitization. The porosity of the precursor limestone depends on the diagenetic history up to the time of dolomitization. Data show that: (1) carbonates are born with high porosity and lose porosity gradually over a long period; and (2) mud-dominated fabrics compact more readily than grain-dominated fabrics. The problem of estimating the time of dolomitization is minimized by confining observations to young limestones and associated dolostones. Limited data from Holocene dolomitic sediments suggest no change in porosity with dolomitization. Study of Plio-Pleistocene carbonates in Bonaire, Netherlands Antilles, demonstrates that precursor limestones are more porous than dolostones. Limestones average 25% porosity, whereas dolostones average 11% porosity. Data from the Neogene of the Great Bahama Bank show that dolostones and adjacent limestones both have 40% porosity. Porosity studies of the Jurassic Arab D Formation show that dolostones and associated grain-dominated limestones have similar porosity ranges and that the decrease in porosity with increasing dolomitization results from compaction of the mud-dominated fabrics. These data suggest that porosity in dolostone is not created by a mole-for-mole replacement mechanism. Instead, dolostone porosity is: (1) inherited from the precursor limestone; and (2) occluded by the process of overdolomitization. Palaeozoic dolostones, however, are commonly more porous than juxtaposed limestones. The explanation for this observation is that limestones lose porosity through compaction and cementation, whereas dolostones resist compaction and retain much of their porosity. Permeability studies have demonstrated that dolomitization of grain-dominated limestones usually does not change porosity-permeability relationships. Instead, precursor limestone fabric controls pore-size distribution. The dolomite crystal size of a muddominated dolostone may, however, be larger than the carbonate mud size, improving the porosity-permeability relationship substantially. Hence, there is a predictable relationship between interparticle (grains or crystals) porosity, permeability, precursor grain size and dolomite crystal size.

A Triple Porosity Model for Petrophysical Analysis of Naturally Fractured Reservoirs

Abstract: The analysis of vuggy and fractured reservoirs has been an area of significant interest in the past few years. Several researchers have studied the characterization of these reservoirs using dual porosity models and have looked for means of estimating values of the dual porosity exponent m for use in calculations of water saturation. There are instances where the reservoir is composed mainly of matrix, fractures and non-connected vugs. In these cases a triple porosity model appears more suitable for petrophysical evaluation of the reservoir. A new technique is presented for these- types of reservoirs that is shown to hold for all combinations of matrix, fracture, and non-connected vug porosities. At low porosities, the fractures dominate and the m values of the composite system tend to be smaller than the porosity exponent of the matrix (m b ). As the total porosity increases, however, the effect of the non-connected vugs becomes more important and m of the triple porosity system can become larger than m b . To the best of our knowledge a solution to the problem associated with the triple porosity exponent has not been addressed previously in the petrophysical literature. This research is inspired by the availability of modem magnetic resonance, micro-resistivity and sonic image tools that permit reasonable characterization of complex reservoirs. The use of the triple porosity model is illustrated with an example.

Effects of air injection on flow through porous media: Observations and analyses of laboratory‐scale processes

Abstract: (1) The effects of air injection on flow through porous media were explored in a series of 1-m and 2-m laboratory flow cells Our motivation was to examine air barriers as an alternative to hydraulic barriers to inhibit saline intrusion in coastal areas Steady flow conditions were created in homogeneous and heterogeneous unconsolidated sand systems Dry air was injected at progressively higher flow rates through a well in the center of each flow cell Discharge and NaCltracer breakthrough data were measured at the outflow reservoir of each cell In addition, a dye tracer was used to visualize the flow patterns In all cases, air injection was found to produce stable, low-conductivity barriers that reduced discharge by an order of magnitude or more Effective hydraulic conductivity values determined from discharge and hydraulic head data showed exponential declines with increased air-injection rates in all cases Numerical simulation was used to quantify hydraulic conductivity and effective porosity values in the saturated and aerated regions created by air injection, and to study advective flow behavior Pore-filling cement formed in the air-injection region and was analyzed to determine its composition, mass, and volume Approximately 60% of the cement consisted of soluble minerals, and 40% was less soluble carbonates Evaporation and increase in solution pH due to stripping of CO2 by the injected air were responsible for creating the cement The cement occupied <10% of the pore space in the sand-cement aggregate Both the air and mineral pore-fillings dissolved when air injection ceased, indicating that both barriers are temporary These results serve as a preliminary proof of concept that air-injection barriers might effectively inhibit undesired subsurface flow, such as saline intrusion or contaminated groundwater INDEX TERMS: 1829 Hydrology: Groundwater hydrology; 1832 Hydrology: Groundwater transport; 1875 Hydrology: Unsaturated zone; KEYWORDS: conductivity reduction, containment, seawater intrusion, subsurface barriers Citation: Dror, I, B Berkowitz, and S M Gorelick (2004), Effects of air injection on flow through porous media: Observations and analyses of laboratory-scale processes, Water Resour Res, 40, W09203, doi:101029/2003WR002960

Porosity and Permeability

Abstract: The knowledge of the two properties—porosity and permeability—of rocks is essential to determine the types of fluids, amount of fluids, rates of fluid flow, and fluid recovery estimates in rocks. The porosity of a reservoir rock is defined as that fraction of the bulk volume of the reservoir that is not occupied by the solid framework of the reservoir. The porosities of petroleum reservoirs range from 5% to 30%, but most frequently are between 10% and 20%. Any porosity less than 5% is very seldom commercial, and any porosity more than 35% is extremely unusual. During sedimentation and lithification, some of the pore spaces initially developed became isolated from the other pore spaces by various diagenetic and catagenetic processes such as cementation and compaction. Thus, many of the pores will be interconnected, whereas others will be completely isolated. This leads to two distinct categories of porosity—total and effective—depending upon which pore spaces are measured in determining the volume of these pore spaces. In addition to being porous, a reservoir rock must have the ability to allow petroleum fluids to flow through its interconnected pores. The rock's ability to conduct fluids is termed as permeability. The permeability of a rock depends on its effective porosity and consequently, it is affected by the rock grain size, grain shape, grain size distribution (sorting), grain packing, and the degree of consolidation and cementation.

Analysis of hydraulic and tracer response tests within moderately fractured rock based on a transition probability geostatistical approach

Abstract: [1] A transition probability and Markov chain geostatistical approach is applied to synthesize the discrete permeability structure of moderately fractured rock The approach can infuse either hard or subjective categorical information that is consistent with geological interpretations The methodology is tested using data collected from the Moderately Fractured Rock (MFR) experiment area of the Underground Research Laboratory (URL) in southeastern Manitoba, Canada Attributes pertaining to fracture location, frequency, and orientation along an array of boreholes intersecting the MFR experiment area, taken together with results from hydraulic response tests within packed-off intervals along the boreholes, are used to produce conditional stochastic realizations of hydraulic conductivity and effective porosity Using the generated hydraulic conductivity and porosity realizations, we compare predicted tracer concentrations to the results of measured breakthrough data in a stochastic framework The results show that solute migration behavior in moderately fractured rock can be successfully characterized and reasonably predicted upon careful error analysis of the results obtained from the various medium realizations synthesized from the conditional categorical descriptions of the fractured crystalline rock

Simultaneous measurement of rock permeability and effective porosity using laser-polarized noble gas NMR.

Abstract: We report simultaneous measurements of the permeability and effective porosity of oil-reservoir rock cores using one-dimensional NMR imaging of the penetrating flow of laser-polarized xenon gas. The permeability result agrees well with industry standard techniques, whereas effective porosity is not easily determined by other methods. This NMR technique may have applications to the characterization of fluid flow in a wide variety of porous and granular media.

Xenon NMR Measurements of Permeability and Tortuosity in Reservoir Rocks

Abstract: In this work we present measurements of permeability, effective porosity and tortuosity on a variety of rock samples using NMR/MRI of thermal and laser-polarized gas. Permeability and effective porosity are measured simultaneously using MRI to monitor the inflow of laser-polarized xenon into the rock core. Tortuosity is determined from measurements of the time-dependent diffusion coefficient using thermal xenon in sealed samples. The initial results from a limited number of rocks indicate inverse correlations between tortuosity and both effective porosity and permeability. Further studies to widen the number of types of rocks studied may eventually aid in explaining the poorly understood connection between permeability and tortuosity of rock cores.

Predicting porosity logs from seismic attributes using geostatistics

Abstract: At Pikes Peak, the Lower Cretaceous Waseca Formation, about 450 m below the surface, is the producing reservoir. The Waseca is filled with a homogeneous sand unit, an interbedded sand and shale unit, and a capping shale unit. These sands exhibit lithological variation, which affects the porosity distribution. After a proper well-to-seismic tie, we are able to analyze sample-based seismic attributes and select the most reliable ones using cross-validation. Effective porosity logs and various seismic attributes from PP and PS seismic data were used as inputs for porosity prediction. We have found that a probabilistic neural network showed the highest crosscorrelation (86%) between actual and predicted porosity logs at seven wells in the study area. After validation, the predicted volume of porosity along a 2-D seismic line was displayed. This final section provides a geologically realistic porosity distribution and helps in understanding the subsurface image.

Method for determining formation porosity and gas saturation in a gas reservoir

Abstract: Measurements made with porosity and density logging tools in a gas reservoir may differ due to invasion effects. The effects are particularly large on measurement-while-drilling applications where invasion is minimal. Using a Monte-Carlo method, a relationship is established between true formation porosity and porosity estimates from density and porosity tools. This relationship is used on real data to get an improved estimate of formation porosity and of gas saturation.

Quantitative Discrimination of Effective Porosity Using Digital Image Analysis - Implications for Porosity-Permeability Transforms

Abstract: Five relevant digital image analysis parameters for fluid flow are obtained from 2-D image analysis of carbonate rocks: 2-D image porosity, amount of pores, pore shape, total perimeter per area and dominant pore size range. Micro-porosity leads to low permeable, highly porous rocks. 2-D image porosity represents the macro-porosity because the resolution subtracts the small pores from the porosity. Compared to the total porosity, it improves the prediction of permeability by an order of magnitude in the high porosity range. Pore shape factor γ reduces the uncertainty in permeability prediction to 2 orders of magnitude. Pore shape factor analysis is restricted to samples with more than 4000 pores/cm. CT scans of plugs reveals that the pore shape factor γ is a relatively constant measure of the pore shape (+/0.2) throughout the sample plug. The larger the average pore size, the higher the velocity at a given porosity. The average pore size can be quantified by the upper limit of the dominant pore size range.

Application of medical Computer Tomograph measurements to 3D reservoir characterization

Abstract: This paper summarizes the benefits of non-destructive core measurements by medical Computer Tomograph (CT) in integrated 3D reservoir characterization. A direct relationship exists between CT measurements and petrography, conventional petrophysical analysis and well logs. Based on CT measurements the internal structure of core samples, and the geometry of framework constituents, porosity type and pore size distribution, as well as fracturing, can be described. There is a close connection between distribution of the Hounsfield Unit of CT measurements and pore size distribution detected by conventional petrophysical analysis. Calculation of effective porosity from petroleum saturation experiments provides a new way to determine the porosity of the whole core sample. Beside the description of reservoir parameters, the results of CT measurements can be extended over the surrounding area of the well. By matching the cylinder maps of CT to FMI images and other well logs the original position of the core sample...

Improved log analysis in shaly-sandstones-based on Sw and hydrocarbon pore volume routine measurements of preserved cores cut in oil-based mud

Abstract: Routine measurements of properly preserved cores cut in oil-based mud (OBM) give accurate porosity (Φ) and water saturation (S w ) values in hydrocarbon reservoirs. Above mobile water zones the Hydrocarbon Pore Volume (HPV) of these OBM cores is usually accurate in both clean and shaly sand reservoirs. HPV evaluations from the 'core' and the 'total' and 'effective' porosity systems must all be the same: HPV = Φ core (1 - S wcore ) = Φ t (1 - S wt ) = Φ e (1 - S we ), where the subscripts denote the specific system being addressed. In shaly reservoirs, core porosity (Φ core ) and total porosity (Φ t ) may be larger than effective porosity (Φ e ), with the extra porosity being generated from the drying of the clay minerals, especially smectites. The water volumes measured by Dean-Stark extraction of OBM core plugs includes this clay-bound water, so OBM Φ core and S wcore used together as a pair give an accurate evaluation of HPV. Example core and log data from a shaly-sand formation are evaluated using several well-known log analysis models. As tested, the Dual-Water, Cyberlook and Indonesia models all provide quite similar S w results and agree fairly well with the OBM S wcore corrected to reservoir conditions Because the standard Cyberlook and Indonesia S w results are close to S wt , they are paired with total porosity for HPV calculations. They have previously been thought to give S we , not S wt, and have been paired with 'effective' porosity giving pessimistic HPV results. The Archie total porosity model also gives useful, but pessimistic, results. The Archie effective porosity model gives very pessimistic S w and HPV results in shaly sands. The most accurate evaluation method, the OBM core analysis, can be used to calibrate current resistivity-S w models for shaly sands. This process leads to improved estimates of oil- and gas-in-place and, potentially, to improved shaly-sand models for application in worldwide log analysis.

Formation Resistivity and Water Saturation

Abstract: This chapter discusses that the sedimentary formations are capable of transmitting an electric current only by means of the interstitial and adsorbed water they contain. They would be non-conductive if they were entirely dry. The electrical resistivity of a fluid-saturated rock is its ability to impede the flow of electric current through that rock. Dry rocks exhibit infinite resistivity. The resistivity of reservoir rocks is a function of salinity of formation water, effective porosity, and quantity of hydrocarbons trapped in the pore space. Relationships among these quantities indicate that the resistivity decreases with increasing porosity and increases with increasing petroleum content. Resistivity measurements are also dependent upon pore geometry, formation stress, and composition of rock, interstitial fluids, and temperature. Resistivity is, therefore, a valuable tool for evaluating the producibility of a formation.

Mechanism of the formation of secondary porosity in clastic rock

Abstract: Secondary porosity in clastic rock is an important reservoir for deep oil and gas pools. The dissolution process of meteoric water with relative high fluid velocity and lower temperature is an important mechanism in producing large secondary porosity because it could flow down into the strata regionally and then take off a lot of dissoluted material from dissolution process area. CO_2 resulting from organic thermal evolution is another dissolution mechanism, which may produce effective porosity through the dissolution of the sandstones cemented by carbonate or Al-silicate minerals. Compared to CO_2, Organic acids, which are more dissoluble to minerals, play an important role of porosity forming under the ground. It is concluded that multi-disciplinarian and quantitative research of the formation and development of the secondary porosity and its forecasting method are the main task in this field.

A procedure for delineation of bedrock fracture zones under glacial drift formations in ohio

Abstract: In any aquifer the porosity can be either primary or secondary or a combination of the two, referred to as dual porosity. Primary porosity is the diffused, inter-granular porosity inherent to the rock, generated at the time of lithogenesis. Secondary porosity is the porosity created by post-genetic processes, e.g. fracturing or dissolution of the rock. Rates of groundwater production from bedrock sandstone units are commonly directly related to the presence and extent of secondary porosity. Bedrock fracturing can be product of tectonic stress or, in recently glaciated areas, unloading from the retreat of glaciers. The goals of our study were to test the hypothesis that the values of hydraulic conductivity, computed from the data stored in water well archives for single-home water wells penetrating bedrock sandstone formations may delineate mappable areas of high hydraulic conductivity, thus showing the distribution of fracture zones. We analyzed ninety-one well logs of private single-home water wells drilled through the glacial sediments into the sandstone bedrock formations in Geauga and Portage Counties of Northeastern Ohio. Aquifer thickness in each water well was determined from the lithological profiles, while the specific capacity data from production tests were used to estimate the values of the coefficient of transmissivity for each well. Combination of the two parameters yielded mappable values of hydraulic conductivity. The resulting values of hydraulic conductivity were characterized by a distinctly binary distribution, with low values apparently corresponding to massive un-fractured zones and high values corresponding to fractured zones with dual porosity. Once contoured on a map, these zones appeared clearly, with a transition between the areas of high and low hydraulic conductivity, i.e. high and low potential for groundwater production, respectively.

Evaluation of Trap Properties of Capping Beds in Tuha Basin Using Log Data

Abstract: Log data may be used for calculating shaly capping beds parameters such as thickness, displacement pressure, total porosity, effective porosity, permeability, sand content, etc. Quality parameters reflecting trap properties of capping beds in Tuha Basin are analysed, based on which established is log evaluation model for the trap properties of shaly capping beds in the Basin, thus laying a good foundation for evaluation of trap properties of such beds.

The porosity interpretation model for carbonate reservoir in Tahe Oilfield.

Abstract: The phase states and features of reservoir fluid are not all the same in the different area of Tahe Oilfield. The conventional interpretation model of porosity is affected by the reservoir fluid phase state in great degree and not perfect. The new effective and fracture porosity calculation model is set up by the regression analysis of resistivity and porosity data which is not affected by fluid phase state largely. As a result, the new model improves the precision of total effective porosity and the formation cementation index calculated meets with the analysis results of formation resistivity. The development intervals of fracture porosity matches with the development intervals by core observation, testing proves the oil layer interpreted by the data of fracture water saturation on the basis of new model. The new porosity model is a summarization and integration of effective regression relation. It is adaptive to different areas through the changes of regression equation or parameters and relatively extensive practical.

Method for determining water saturation and fraction of sand bed with use of tool for forming image of specific resistance in drill well, tool for transverse induction logging services and tensor water saturation model

Abstract: FIELD: induction logging services engineering ^ SUBSTANCE: in layered bed, including oil-carrying bed, which may contain dispersed shale, full porosity of bed is determined, including fractional volume of shale and its specific resistance Tensor model determines volume of layered shale and conductivity of layered sand bed from vertical and horizontal conductivities, derived from multi-component data of induction logging services By method of Thomas-Stieber-Juhasz, volume of dispersed shale is determined, as well as full and effective porosity of layered fraction of sand Exclusion of conductivity of layered shale sand and porosity effects simplifies problem of layered shale sand, to which Waxman-Smits equation is applicable ^ EFFECT: higher precision ^ 2 cl, 6 dwg

Absolute and Effective Porosity

Abstract: This chapter provides an overview on absolute and effective porosity. The most basic property of reservoir rocks is porosity that allows the rock to store fluids such as gas, oil, and water. The total volume of fluid that can be stored in a given bulk volume of rock is its pore volume. The solids volume is the portion of the rock comprised only of solid matter. The total exterior or bulk volume, of the rock is, therefore, the sum of the grain and pore volumes. The total, or absolute porosity, is the pore volume divided by the bulk volume. The void ratio is the pore volume divided by the solids volume. The complex internal structure of pores in rocks frequently results in the formation of isolated pores. These isolated pores contribute to the overall porosity of the rock, but are not interconnected to the main body of pores and, therefore, are not involved in the flow of fluids through the rock. The interconnected pores that support the flow of fluids make up the effective porosity, which is numerically less than the absolute porosity, that is, the intercommunicating porosity excluding the pores containing irreducible fluid saturation. The small pores occupied by the irreducible fluid, and cracks and dead-end pores are not involved in the flow process.

Reservoir categorization of tight gas sandstones by correlating petrophysics with core-measured capillary pressure

Abstract: Tight gas sandstones have the characteristics of medium to low porosity, low to very low permeability and variable porosity/saturation relations. Often a free water level is difficult or impossible to identify in the wellbore. Erratically changing profiles of porosity and saturation are difficult to interpret with respect to identification of pay intervals. Additionally, in some areas water salinity varies. Sometimes there is a mixing of wet sandstones with gas-bearing sandstones, with both groups having high resistivities and not always easy to differentiate. A method is described whereby detailed examination of density and neutron responses can quantify this distinction. A second technique presented here involves linking capillary pressure saturation/depth profiles with petrophysically-defined porosity and saturation depth profiles. Source core capillary pressure data should be from the same reservoir sequence, but not necessarily from the same well. Core samples, showing a range of porosity/permeability relationships, are analyzed to yield a spectrum of saturation/height relationships, linked to porosity. Integration into petrophysically-defined saturation/porosity profiles involves first a choice of the free water level interpreted to control the gas within a continuous hydraulic unit. This level may be below the total depth of the well. Then, a spectrum of saturation/height curves is calculated, specific to the petrophysically-defined porosity profile. Finally, a comparison with petrophysically-determined saturation permits an automatic definition of rock quality, mobile vs. immobile water and permeability. By incorporating relative permeability concepts, profiles of effective permeability to each fluid (gas and water) can be estimated. Flow units can be differentiated from barriers. The data can also be used to identify which intervals should be completed, and which zones should be isolated from one another.

Application Of Seismic Inversion In Integrated Characterization of Carbonate Reservoirs: A Case Study From Mumbai High, India

Abstract: D seismic inversion has been qualitatively and quantitatively used in the reservoir characterization of the South- Eastern part of North Mumbai High field. The inverted impedance volume has been integrated with geological, petrophysical and production data of existing wells to bring out detailed reservoir heterogeneity in a multi-layered, diagenetically complex, pro ducing carbonate reservoir of Mumbai High. Qualitative and quantitative integration of layer-wise acoustic impedance with production data, core data, seismic facies and porosity has come out with improved reservoir predictions. The acoustic impedance has shown a fairly good correlation ( Correlation coefficient above 65%) with effective porosity and has been integrated using collocate d co- kriging option resulting in generation of layer-wise porosity maps with reduced inter-well uncertainty. Subsequent drilling of wells has validated the results.