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Second EAGE Workshop on Rock Physics
- Conference date: 12 Jan 2014 - 14 Jan 2014
- Location: Muscat, Oman
- ISBN: 978-90-73834-73-6
- Published: 12 January 2014
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Static Moduli Prediction Using Integration Between Rock Physics and Dynamic Moduli
By A. PetrovIn general earth is a stressful place. The rapid deposition of sediment generates pressure differentials that can result in deeper overpressure zones, which are hazards to drilling operations [3]. Earth stresses also influence other aspects of reservoir evaluation and development. Stress magnitude and orientation affect fracture initiation and propagation. Weakly consolidated formations also may fail into the wellbore because of compressional stresses at the well wall due to the borehole breakout. This refers to the fact that stresses have most effects on the formations within weak reservoirs and it should be considered beforehand. Therefore, nowadays geomechanical studies are a necessary step within drilling, completion and exploitation operations. Failure to perform such studies and understand the geomechanical properties can be resulted in expensive risks. As a result developing a consistent mechanical earth model can reduce operation risks and may provide benefit throughout the life of the field.
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Rock Physics Characterization of Light Tight Oil Plays
Authors S. Al-Farsi, S. Al-Mahruqi, K. Mohammed, H. Cornelius and S. AntonioRecently Petroleum Development Oman (PDO) embarked on a campaign to explore the existence, extend and commerciality of a number of light tight oil plays. One of them exists in the Pre-Cambrium group of south Oman, the other one in the Cenomanian source rock formation of North Oman. Both Formations are tight with porosities ranging from 0 to 10% and permeabilities ranging from 0.001 to 0.4 mD. In order to access these potentially recoverable volumes, these and future wells need to be stimulated via hydraulic fracturing. The geomechanics team was involved at the early stage of the exploration wells to plan deign the data acquisition program for the purpose of geomechanics assessment. This includes wire line logs, laboratory test and other field measurements such as micro-frac. Using the acquired log and laboratory data, 1-D calibrated geomechanical models were built on a well by well basis for four vertical wells. The objective of the Geomechanical analysis, carried out for this project, was to provide input to the hydraulic fracturing design for each well. The main assessed parameters were: stress profile, Elastic Moduli (Young Modulus and Poisson ratio), fracture toughness and rock strength. All these parameters were derived from the acquired logs and calibrated against the laboratory measured data,
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Petrophysical Rock Texture Prediction in the Upper Jurassic Series in Saudi Arabia: Aiming Toward Stratigraphic Trap Identification
More LessThe Upper Jurassic series comprises the most prolific hydrocarbon-bearing formations in Saudi Arabia. It consists of 7 formations which are 3rd order sequences of about 2.5 Ma each. It hosts 13 hydrocarbon reservoirs, 2 major source rock intervals and good associated seals. The total thickness of carbonates and evaporites in the Upper Jurassic series, in the study area is greater than 3500 feet (Figure 1). Predicting the rock texture distribution with the use of wireline logs can help us subsequently identify the potential reservoir facies distribution and that, in turn, can be used for stratigraphic trap identification.
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Petrophysics and Nuclear Magnetic Resonance (NMR) Study of Low-Resistivity Pay in Lower Silurian Sandstone Reservoir
By L. MarzoukKnowledge of reservoir evaluation is helpful in the interpretation of well-logging data, where the hydrocarbon saturation is expected as the final result by Archie equation. It is calculated from the deep resistivity, water formation resistivity and porosity. Porosity is calculated from the bulk density, neutron and sonic are measured directly in the well. The Archie evaluation, in the low resistivity layers, is characterized by high water saturation. The MDT tests in the low resistivity pay prove several oil samples. For this incompatibility interpretation of low-resistivity-contrast pay zones needs an analysis of the reservoir composition in the study area. The divergence results between Archie and well test allow integrating a new evaluation approach. However, the proposed interpretation framework does allow the incorporation of new logging technology as this becomes established. Nuclear magnetic resonance (NMR) is a useful tool in reservoir evaluation. The objective of this study is to predict petrophysical properties from NMR T2 distributions. The evaluation of NMR relaxation time distributions estimates of pore-size distributions. Irreducible water-saturation estimates from NMR-based pore-size distributions. In this study, we look at the downhole NMR measurements to determine pore geometry and volumetrics within a reservoir (free fluid index). NMR measures the net magnetization of a hydrogen atom (H) in the presence of an external magnetic field. Hydrogen has a relatively large magnetic moment and is abundant in both the water and hydrocarbons that exist in the pore space of sedimentary rocks. NMR measurements provide information about the pore structure (Sp), the amount of fluid in situ (FFI), interactions between the pore fluids, and surface of pores and provide important information for evaluation of low-resistivity layers.
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Promises and Pitfalls: Acoustic Properties in Carbonate Rocks
By G.T. BaechleThe acoustic properties of the matrix in carbonate rocks are affected by three main factors: pore fluids, rock framework and pore space configuration. In carbonate rocks, the latter two factors are a function of the depositional environment and the diagenetic history. Cementation, recrystallisation and dissolution processes can change the mineralogy and texture of the original framework and thereby alter the original grain-to-grain contacts and/or occlude pore space. Dissolution processes can enlarge interparticle pore space or dissolve grains entirely, thereby increasing porosity. Ultrasonic measurements of core plugs show that these diagenetic alterations and associated changes in the rock frame and pore structure result in a wide range of p-wave velocity at a given porosity. Understanding the effect of pore types on acoustic properties of carbonate rocks is vital for reliable porosity determination from seismic signatures. In addition, I will point out some pitfalls in relating pore type effects to observed acoustic properties responses.
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Permeability Predictions from Acoustic Core Measurements
By A. DraegeCore measurements published by Weger et al. (2009) are used as a training dataset. We have used a modified version of the rock physics model for carbonates of Sun (2000, 2004), to estimate permeability solely as a function of P-wave velocity and porosity in brine saturated carbonates. The results were tested against an independent database with 101 carbonate core measurements from seven different locations. The test results are promising, indicating that over 72 % of the permeabilities can be predicted within one order of magnitude. An analysis of the prediction errors indicated the validity areas of the model. The model struggles to reproduce permeability in high porous - low permeability rocks, which from thin sections were found to be oomoldic. Also low porosity - high permeability carbonates were difficult to predict. It is shown that integration of the developed model with geological knowledge will improve the prediction accuracy. This methodology elucidates the intricate link between carbonate rock frame stiffness and pore structure flow properties. It offers the potential to improve permeability predictions from wireline sonic data.
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QI Workflow to Identify Sweet Spots in the Tight Amin Gas Play in North Oman
More LessAs conventional hydrocarbon plays have become more mature, Petroleum Development Oman LLC (PDO) is increasingly focusing towards tight plays. The Amin reservoir is such a play and consists of alluvial sandstone reservoir with high net-to-gross but low porosity and permeability. One of the wells within the area of interest has encountered high overpressures with good porosity in the Amin reservoir and triggered a quantitative interpretation study to identify sweet spots for drilling and to map out fracture networks at target level. This study is split into two sections: the first part consists of a conventional deterministic AVO inversion and the second part describes the application and interpretation of the near offset Ruger equation and of a 3D simultaneous azimuthal inversion. The outcome from part one resulted into a predictive porosity map, which was confirmed by an additional well. Hence, the porosity map has been included in the static model to guide the porosity distribution. The results from the second part are encouraging but qualitative and in addition confirm the findings in surrounding wells. However, more calibration as well as production data is required to accomplish a more quantitative interpretation of these computed volumes. Later this year another well will be drilled.
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Complex Paleozoic Clastic Systems: Reducing Field Development Uncertainties with Quantitative Seismic Interpretation Workflows
Authors M. Ahmed, J. Ahmad, H. Soepriatna and A. ReesPaleozoic clastic reservoirs in Central and Eastern Saudi Arabia are complex deposits and present a unique challenge in terms of field development cycles. The Unayzah Formation represents the youngest siliciclastic Paleozoic unit to be deposited before the regional transgression in the late Permian. In Central Arabia, the Unayzah Formation unconformably overlies Silurian rocks and ranges in thickness from 60 to 850 feet. (King, 1996) Standard quantitative seismic approaches in mapping the potential hydrocarbon-bearing layers have been addressed, initially by Melvin et.al. (2010), but are inadequate to fully understand the variations in reservoir fluid and mineralogy. To address this challenge, an integrated work flow was developed and is presented in this paper as a case study. A detailed core description was integrated with rock physics principals to first address the effect of fluid and varying mineralogy on the elastic properties. Secondly, the seismic data was reprocessed using Saudi Aramco proprietary algorithms for AVO inversion workflows. Rock physics models enveloping the field scale sedimentological framework were then used to transform the standard AVO inversion elastic properties’ into 3D lithofacies with associated probabilities. The results have proved to be encouraging in terms of providing a spatial understanding of the hydrocarbon-bearing clastic reservoir and also in reducing uncertainty in the placement of development wells.
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Rock Property Analysis for Visualization of Upper Gharif Fluvial System Using Spectral Decomposition, Sultanate of Oman
Authors H. Salem, D. Alsop, Y. Aufi and L. Bazalgetteplease note: MOG approval is still pending. The early Permian Gharif Formation is a major producing oil and gas reservoir in the Sultanate of Oman. The Upper Gharif subdivision is known for its continental fluvial depositional environment. Seismic tools were commonly used for imaging the reservoir distribution. However, seismic resolution can be an obstacle for resolving complex reservoir distribution. Rock property extraction using well data helped to better understand the behaviour of the reservoir using synthetic forward modelling. Spectral decomposition along with sculpting proved an efficient technique for imaging the Gharif reservoirs. The amplitudes change with frequency due to the tuning between the top and base of the geo-bodies (Castagna et al., 2003). The detected geo-bodies were then integrated with well results and outcrop data for verification. In this paper we will represent how the rock property analysis helped to guide the visualization endeavours to detect the sand reservoirs. Besides, how the generation of discrete frequency volumes using spectral decomposition helped to reveal the distribution of the sand fluvial channels. Two fields in North and Central Oman will be taken to illustrate this paper.
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Rock Physics Modeling Guided by Depositional and Burial History in Low to Intermmediate Porosity Sandstones
Authors T.A. Johansen, P. Avseth, A. Bakhorji and H.M. MustafaPrediction of reservoir properties as porosity (P), type of pore fluid (F) and lithology (L) from seismically derived properties as for instance the P-to-S velocity ratios (Vp/Vs) and P-wave acoustic impedances is crucial in quantitative seismic interpretation. The most common strategy is to cross plot the seismic parameters, obtained from data, within Rock Physics Templates (RPT) (Avseth et al., 2005) where certain projections of results from forward rock physics modelling have been embedded. Figure 1 shows one example where 29 synthetic data points have been plotted within an RPT made for consolidated siliciclastic rocks. The synthetic data points cover a span in porosity, gas-to-water saturation and lithology (clay-tosand ratio). The continuous lines define the shale line (upper left) and sand line (lower curve), where pore fluid is water and porosity increases from 0 to 0.3 from right to left for both lines. For various porosities along the water-filled clean sand line fluid substitution effects, gradually exchanging water with gas, are displayed. Studying the RPT we can see no specific trends in the data since all the before mentioned reservoir parameters vary. Only some few data points are captured by the clean sand projection. In this paper we present the concept of Inverse Rock Physics Modelling (IRPM) which aims to capture all combinations of the reservoir properties which correspond to a set of data points, given a specific underlying rock physics model. In Figure 2 the results from an IRPM are shown, where each data point now is associated with a numerical correlation function of the reservoir parameters. The approach thus gives the full suite of possible solutions representative for each data point, and thus more specifically reveals the non-uniqueness in estimation of PLF-parameters from seismic parameters
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Rock Physics and Seismic Characterization of Oman’s Unconventional Reservoirs
Authors A.-M.H. Wulff, S. Scholten and J.G. RehlingThe hydrocarbon system of Oman contains a multitude of excellent source rock intervals. Following the outcome of a play based evaluation study for the unconventional hydrocarbon potential Petroleum Development Oman has recently drilled several exploration wells to test the presence of a Liquid Rich Source (LRS) play in Oman. All wells have found good source rocks and oil has been successfully recovered. The main target intervals are two significantly different depositional systems of very different ages: The carbonate-rich Cretaceous Natih-B intervals and the Pre-Cambrian Nafun Group. Rock physics relationships together with quantitative interpretation can help to assess some uncertainties related to the Oman unconventional plays. In particular for the Nafun LRS play the TOC distribution can be deduced from good quality seismic data. For the Natih LRS play porosity distribution and possibly also TOC variations are estimated from currently available seismic volumes. This information is valuable for the placement of upcoming exploration wells as well as for improving the stratigraphy understanding.
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An Integrated Solution to Rock Physics Modelling in Fractured Carbonate Reservoirs
More LessAn integrated workflow is presented to model the seismic response of a fractured carbonate reservoir. Carbonate rocks are known to have a more complicated, heterogeneous pore structure than sandstone rocks. The workflow uses P-wave and porosity log data to calibrate a multi-porosity model using the extended Xu-White model (Xu and Payne, 2009). The model is then up-scaled to investigate the low frequency seismic response through the inclusion of aligned meso-scale fracture sets. Analysis is shown for log data measured in a fractured limestone reservoir. The rock physics model was used to predict the P-wave and P-to-S wave reflectivity from the top of the limestone reservoir. The results demonstrate that rock physics is able to play an important role in modelling and characterizing the seismic response of carbonate reservoirs.
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Update on Digital Rock Physics for Oil and Gas Shales
More LessKey Digital Rock Physics applications for shales as well as carbonates, tight gas sands and complex clastics are •Transform special core analysis (SCAL) as practiced today – speed, accuracy, many samples from many facies and rock types •From core repositories create large rock property data bases of relative perm, cap pressure, mechanical properties etc – all on the same sample •Populate mega size Reservoir simulators •From cuttings obtain permeability, elasticity, and fractability logs at the wellhead in quasi real time •Enable much more rigorous links between rock properties and logs •Link log and rock properties and seismic to look away from the borehole (“drill virtual wells from seismic”) •Significantly enhance the interpretations of time-lapse geophysics/monitoring
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Towards a Representative Rock Model from a Micro-CT Image
Authors E.H. Saenger, C. Madonna, N. Tisato and B. QuintalDigital rock physics combines modern imaging with advanced numerical simulations to analyze the physical properties of rocks. However, it remains difficult to resolve microstructures on submicrometer scale and image a representative volume at the same time, which is essential to understand the elastic properties of rocks. This leads to a mismatch between laboratory measurements and digital rock physics estimates. In this paper we suggest the usage of digital rock physics templates as recipe to obtain accurate numerical predictions. In those templates optimized pressure-dependent elastic properties are given for each phase of a rock identified on a micro-CT image. For one Berea sandstone sample we describe such a template by using a laboratory-based calibration technique.
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Is it Possible to Predict Porosity at Different Scales?
Authors S. Vega, M. Soufiane Jouini and E. Amin MokhtarScaling in general is referred as mathematical transformations that allow calculating object characteristics from one scale to another. In Earth Sciences, we are interested to scale rock properties from the scale of measurement to the scale of modelling, as they are usually different. In particular, when there are only rock fragments or cuttings available, porosity can be extracted from SEM and/or thin sections using image processing. When there are cores available, porosity can also be measured from core plugs using, for example, gas porosimeters (Boyle’s law) or NMR lab measurements. However, the main issue is how to extrapolate these values to the wells and field scales. In other words, is there any scaling law or transformation that can be used for going from lab scale measurements to field scales or vice-versa? Previous works have shown fractal behaviour in pore space of some soils, sandstones and carbonates (e.g. Thompson et al. 1987; Posadas et al. 2001; Xie et al. 2010). As fractal geometry involves self-similarity and its corresponding power laws, it seems that scaling using this mathematical formalism is a promising implication. As a matter of fact, fractal porosity in sandstones has been found to be proportional to the ratio between the minimum and maximum limits of self-similarity to the power of D-Do, where D is the Euclidian dimension (2 for SEM and thins section images and 3 for full core plugs images) and Do is the corresponding fractal dimension or capacity dimension (Thompson et al. 1987). However, this fractal porosity relation implies that self-similarity might be limited or constrain to certain scales. If it is not constrained to the measure scales, which is indeed the need; it is very difficult to find. Few studies have shown multifractal behaviour in carbonate rocks. Multifractal systems are more complex than fractals. The multifractal systems present more than one exponent and one singularity, while the fractals possess only one. Xie et al. (2010) have presented an analysis of SEM images from Permian-Triassic carbonate rocks, showing that all their samples behave as fractal/multifractal. However, their samples have a very small range of porosities – between 0.4 to 8.8 %. On the other hand, it is not clear yet if the found power laws could be used to scale rock properties as porosity and permeability to field scales, except for Muller et al. (1995). Muller et al. (1995) have found a good and clear correlation between the multifractal exponent (D1) from SEM images and permeability from core plugs in chalk samples. In this paper, we aim to investigate if it is acceptable to generalize multifractal behaviour to all type of carbonate rocks, and if it is possible to estimate porosity at different scales using fractal geometry. To accomplish this, we use a set of carbonate samples from the Upper Cretaceous with a considerable range of porosities – between 1 to 31 %, and different type of rocks (mudstones, packstones, grainstones, wackestones, and rudstones).
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