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Collaborating Authors
University of Calgary
Amplitude-preserving Weights For Kirchhoff Prestack Time Migration
Geiger, Hugh D. (University of Calgary)
Summary In a "Kirchhoff" (i.e. weighted diffraction stack) prestack migration, the summation over a complete diffraction surface can be thought of as an average of reflectivity estimates from migrated common-shot, common-receiver or common-offset gathers. The optimal weight for averaged reflectivity should be based on Bleistein et al''s (2001) ? common-offset weight. In comparison, the ? common-shot and common-receiver weights, although correct for individual gathers, produce average reflectivity estimates with a dip- and depth-dependent bias. Bleistein et al''s (2001) ?1 common-offset weight is more suitable as a basis for practical weights because it downweights by the cosine of the ray half-opening or obliquity angle at the reflector and hence accounts for the corresponding reducedspatial resolution as obliquity angle increases.
Summary An important practical question for multicomponent seismic surveys is how absorption impacts shear or converted wave resolution compared with that of P-waves. In this paper we undertake a comparative analysis of the expected effect of constant Q absorption on different modes, illustrating these effects by modeling absorption for homogeneous and layered models. We find that when S and P-wave attenuation filters are compared in depth, they are exactly equal for the same Q value, in the homogeneous case.
- Geophysics > Seismic Surveying > Seismic Processing (1.00)
- Geophysics > Seismic Surveying > Multicomponent Seismic Surveying (1.00)
Mapping the P-S Conversion Point In Vertical Transversely Isotropic (VTI) Media
Yang, Jianli (University of Calgary) | Lawton, Don C. (University of Calgary)
An important aspect of converted-wave (P-S) seismology is that the exact location of P-S conversion point at the reflector is not well known. In VTI media, there can be a large difference between the true coordinate of the conversion point and the one obtained from the assumed isotropic case. This horizontal displacement of the conversion point in VTI media from that in the isotropic case is dependent on the offset-to-depth ratio, P and S velocity ratio, and anisotropic parameters ε and δ. A raytracing algorithm to calculate this relationship was developed using Thomsen's exact velocities equations in VTI media. We conclude that when ε is equal to or smaller than δ, the conversion point is displaced towards the receiver relative to its location in an isotropic medium. When ε is larger than δ, the conversion point moves towards the source compared to that in the isotropic medium.
Summary Two seismic tests have been conducted around Maya pyramid ruins in Belize, Central America in June 2000 and March 2001. The purpose of the surveys was to test whether a hammer-seismic technique could propagate energy through the carbonate-rubble and mortar pyramids and if this energy could then be used to make images of the interior of the structures. We find that high signal-to-noise first arrivals can be picked on all of the data. First-break arrivals were used from vertical component traces with a traveltime inversion to estimate the velocities inside the pyramid. Velocity contour maps were created with associated resolution and reliability analyses.
- North America > Belize (0.69)
- North America > Central America (0.65)
- North America > United States > Kansas > Barton County (0.29)
- North America > United States > Utah (0.19)
A Robust Algorithm For Constant-Q Wavelet Estimation Using Gabor Analysis
Innanen, Jeff P. (University of Calgary) | Margrave, Gary F. (University of Calgary) | Lamoureux, Michael P. (University of Calgary) | Aggarwala, Rita (University of Calgary)
Summary Seismic attenuation can be modeled macroscopically via an exponential amplitude decay in both time and frequency, at a rate determined by a single dimensionless quantity, Q. Current deconvolution methods, based on the convolutional model, attempt to estimate and remove the embedded causal wavelet. We propose a nonstationary seismic model, expressed in the time-frequency domain, in which (1) the embedded causal wavelet factors as the product of a stationary seismic signature and a nonstationary exponential decay; and (2) a nonstationary impulse response for the earth is tractable. Least squares fitting our model to the Gabor-transformed seismic trace yields a Q-value and an estimate of the source signature, hence an estimate of the nonstationary wavelet. These estimates lead to a smoothed version of the magnitude of the Gabor spectrum of the seismic trace, from which a least-squares nonstationary minimum-phase deconvolution filter is easily constructed.
- Geophysics > Seismic Surveying > Seismic Processing (0.87)
- Geophysics > Seismic Surveying > Seismic Modeling (0.55)
Evaluation of the Miscibility and Contribution of Flue Gas to Oil Recovery Under High Pressure Air Injection
Shokoya, O.S. (University of Calgary) | Mehta, S.A. (University of Calgary) | Moore, R.G. (University of Calgary) | Maini, B.B. (University of Calgary) | Pooladi-Darvish, M. (University of Calgary) | Chakma, A.K. (University of Waterloo)
Abstract The improvement in the recovery of light oil by high pressure air injection (HPAI) involves a combination of complex processes, each contributing to the overall recovery. One of these processes is the spontaneous ignition of the air-oil mixture with complete oxygen utilization. This process generates flue gases, which are in contact with the reservoir oil at the displacement front. An experimental study was carried out to investigate the mechanism and contribution of miscible displacement, by in situ generated flue gases, to the recovery of light oil in reservoirs undergoing HPAI. The flue gas displacements were carried out on recombined reservoir oil in a slim tube apparatus at a reservoir temperature of 116 º C and pressures ranging from 27.77 MPa (4,028 psi) to 46.06 MPa (6,680 psi). Results show that miscibility could not be achieved between the test oil and flue gases under the test conditions. Experiments conducted between 41.28 MPa (5,987 psi) and 45.04 MPa (6,532 psi), however, gave an indication of near-miscible displacement of the test oil. The flue gases displaced the oil in a forward contacting extraction process, resembling a combined vapourizing/condensing multi-contact gas drive mechanism. The relatively high recovery, high extraction of oil components, and the pattern of flow behind the displacement front, exhibited at high pressures, demonstrate that near-miscible displacement by in situ generated flue gases could significantly contribute to oil recovery in light oil reservoirs undergoing HPAI. Introduction Air injection into high pressure reservoirs is an emerging technology for the enhanced recovery of light oils. It is probably the best hope for improved recovery from the world's ever declining reserves of conventional oil and, in particular, the profitable enhanced recovery of the enormous quantities of residual oil trapped in depleted and mature waterflooded light oil reservoirs(1, 2). Air is the most inexpensive, available gas that can be used to accelerate oil recovery. Air injection is especially applicable in low porosity and low permeability reservoirs where water injectivity is extremely low(3). Apart from providing a better interfacial tension (IFT) response(4), air injectivity is about ten times that of water in terms of reservoir volume(5), making air injection more advantageous than water injection in deep, tight, high pressure reservoirs. A number of successful high pressure air injection projects in light oil reservoirs have been documented in the literature. Most of these projects have been operating for many years, attesting to their technical and economic success. The improvement in recovery of light oil by HPAI involves a combination of complex processes, each contributing to the overall recovery. These processes include: reservoir pressurization, oil swelling, immiscible gas displacement, and superextraction when operating above the critical point of water. In addition to this, spontaneous oil ignition with complete oxygen utilization(2, 12, 13) and near-miscibility/miscibility of the in situ generated flue gases with the reservoir oil(13) are possible and advantageous processes. Apart from reservoir pressurization, oil swelling, and immiscible gas displacement, the mechanism by which the other processes occur in the reservoir and their contribution to oil recovery have not been discussed in clear terms in the technical literature(14).
- North America > United States (1.00)
- Asia (1.00)
- North America > Canada > Alberta (0.95)
- Research Report > New Finding (1.00)
- Research Report > Experimental Study (0.88)
Abstract Physical dispersion is one of the main mechanisms responsible for controlling the gas-oil mixing that occurs in a miscible flood process. Many conventional reservoir simulators do not explicitly account for the physical dispersion and presume that it may be compensated by numerical dispersion arising out of the finite difference scheme with single point upstream weighting of mobilities for the reservoir grid block sizes used in field-scale simulations. This assumption may lead to erroneous results. The multi-point flux approximation (MPFA) schemes developed in recent years provide improved treatment of the convective flux and allow the handling of tensorial permeabilities for non-uniform and skewed grids. These grids are often required for proper representation of the reservoir geometry. The physical dispersion coefficient in the dispersive flux is tensorial in nature and amenable to a treatment similar to the permeability in the convective flux. We have applied a multipoint control-volume method together with a total variation diminishing (TVD) scheme to calculating the dispersive flux in a compositional simulator. The TVD scheme was used to minimize the effect of front smearing caused by numerical dispersion. This paper presents a method for calculating the full physical dispersion tensor in a compositional simulator using corner-point grids. The proposed formulation accurately handles dispersive flux for non-orthogonal grids, and along with the TVD scheme provides a means for distinguishing physical dispersion from numerical dispersion. A number of cases are presented to show the improvements in simulation results that could be obtained with the proposed method. Introduction Dispersive mixing plays an important role in the performance of a miscible displacement. It determines how much of the solvent will mix with the in-situ oil to promote miscibility under favorable conditions. Dispersion is the process of distributing or spreading concentration profiles due to mechanisms in which the flux is proportional to the concentration gradient. Diffusion is a special case of dispersion when the velocity of the fluid is zero. Perkins and Johnston provided a comprehensive review of dispersion phenomena in porous media and presented correlations for longitudinal and transverse dispersion coefficients to assess dispersive mixing. Two basic elements of dispersive mixing are molecular diffusion and mechanical dispersion. Mechanical dispersion is induced by variation in the convective velocity field created by the tortuous flow paths of the porous network. The inhomogeneity in porous medium promotes mechanical dispersion. Molecular diffusion, however, takes place solely due to concentration gradient, with or without the presence of motion. In a gas displacement process, a number of crossflow mechanisms are responsible for mass transfer effects, viz., diffusion, mechanical dispersion, capillary pumping, interfacial tension effects and relative permeability modification. The present paper deals primarily with the first two mechanisms i.e. molecular diffusion and mechanical dispersion. Several researchers have studied the sensitivity of the level of dispersion on oil recovery in single- and multi-dimensional models under varying miscibility conditions. In these studies the grid block size was adjusted to mimic the desired level of physical dispersion. In a recent paper, physical dispersion coefficients for an idealistic class of heterogeneity were replaced by controlled numerical dispersion using appropriate grid and time step sizes. Young used the convection-diffusion equation and a one-dimensional grid to model the multi-contact miscible process by treating the dispersion coefficient as a function of the viscosity gradient. The formulation used centered differences for evaluating convective and dispersive fluxes.
Low Field NMR Water Cut Metering
Wright, Ian W. (Tomographic Imaging and Porous Media Laboratory) | Lastockin, David (Tomographic Imaging and Porous Media Laboratory) | Allsopp, Kevin (Tomographic Imaging and Porous Media Laboratory) | Evers-Dakers, Maureen (Canadian Natural Resources Limited) | Kantzas, Apostolos (University of Calgary)
Abstract We have developed a new on line water cut meter using low field Nuclear Magnetic Resonance (NMR) technology. This instrument is designed for use on heavy oil systems where conventional instruments experience difficulties. We present laboratory and field data for application of low field NMR to water cut measurements of bitumen/water mixtures. Data from successful field tests near Cold Lake, Alberta, Canada, shows that the instrument is capable of making water cut measurements over a wide range of fluid types and temperatures. We have successfully measured fluid streams with temperatures ranging from 60 to 150 degrees Centigrade and with water cut ranging from 40 to 95 percent. The instrument is capable of functioning accurately over a wide range of emulsions and/or foams and through significant variations of water salinity. The current application is for water cut measurements on a well site. However, the instrument can be applied in any system where heavy oil, bitumen, water, gas and solid systems may be encountered. It can be used for water cut and/or for three phase (oil/water/gas) volume fraction measurements. The instrument is equally capable of performing well site monitoring for regulatory/reconciliation purposes, for characterizing produced fluids, in separation, pipelining and upgrading processes for process control and for quality testing. Introduction One of the most challenging problems in the production and processing of heavy oil and bitumen is the task of measuring the flow of oil and water. Most instruments have been designed for conventional crude oils and perform poorly when applied to heavy and viscous hydrocarbons. We have developed a new water cut measurement tool specifically for use on heavy oil and bitumen streams. This tool is based on low field Nuclear Magnetic Resonance (NMR) and has shown great promise as an on line tool in use at a field in northern Alberta, Canada where bitumen in being produced using cyclic steam injection. This project is an extension of considerable experience in the lab with core analysis. The initial stages in this particular project have been discussed elsewhere. In brief initial experiments consisted of measuring both known and unknown discrete samples of oil/bitumen and water mixtures in a lab NMR instrument similar to what was used here. Some measurements were also made using unknown samples collected at the wellhead and placed in the instrument with no further preparation. Excellent correlations between NMR measurements and Dean-Stark analysis (approximately 99%) have been reported from this work. The next step was to build an on line tool based on this technology. The field results are reported elsewhere, but the results have generally been viewed as excellent with this technology being in general at least as accurate as other tools typically used on these types of oil fields. This paper attempts to explain the technology and how it works.
- North America > Canada > Alberta (0.54)
- North America > United States > Texas (0.46)
Viscosity Predictions for Crude Oils and Crude Oil Emulsions Using Low Field NMR
Bryan, J. (University of Calgary) | Kantzas, A. (University of Calgary) | Bellehumeur, C. (University of Calgary)
Abstract Knowledge of oil viscosity is vital to the petroleum industry, and is especially important when considering production of heavy oil and bitumen. As viscosity increases, conventional measurements become progressively less accurate and more difficult to obtain. Oil viscosities measured in the lab may also be not indicative of true in-situ viscosities. An alternate method is required for predicting oil viscosity, especially if this method can be applied in-situ. Stable crude oil emulsions are prevalent in many stages of the production and transport of heavy oil and bitumen. Knowledge of emulsion viscosity is necessary for determining energy requirements for transport and upgrading of the produced crude. Low field nuclear magnetic resonance is examined in this work for its potential to predict viscosity of crude oil and crude oil emulsions. NMR is an attractive alternative to conventional viscosity measurements, because it can provide fast, unbiased and non-destructive data. A correlation is presented that predicts fluid viscosities from under 1 cP to over 3 000 000 cP over 25–80°C, making it valid over a wider range of viscosities and temperatures than any other published NMR viscosity correlation. With tuning, this model can predict very accurate changes in viscosity with temperature for a single oil. An NMR emulsion viscosity model is also presented that uses the oil viscosity and water fraction, both determined from NMR, to predict emulsion viscosity. This correlation is able to provide order of magnitude emulsion viscosity predictions for a wide range of emulsion water cuts and viscosities. Work has also been done to extend the viscosity predictions to in-situ viscosity measurements, which can then be extracted from logs. Preliminary findings on in-situ oil viscosity are encouraging, and indicate that NMR has great potential as a tool for in-situ viscosity determination. Introduction Knowledge of oil viscosity is essential to many areas of the petroleum industry, from reservoir engineering and enhanced oil recovery to upgrading and transport of produced fluids. When producing heavy oil and bitumen, the high viscosities are one of the major impediments to recovering these oils. Oil viscosity is often correlated directly to the reserves estimate in heavy oil and bitumen formations, and can determine the success or failure of a given EOR scheme. As a result, viscosity is an important parameter for doing numerical simulation and determining the economics of a project. Water-in-oil emulsions, also known as crude oil emulsions, are also prevalent in the industry. All oil is produced along with some water, and for heavier crudes, which are usually produced using injected steam, the water cut can be significant. Knowledge of emulsion viscosity can aid in determining energy requirements for transport and upgrading of these fluids. As viscosity increases, conventional measurements become progressively less accurate and more difficult to obtain. Oil samples and emulsions extracted and measured in the lab may also no longer be representative of in-situ or on site conditions. An alternate method of measuring the viscosity of crude oils and crude oil emulsions would therefore be of great value to the petroleum industry. Low field nuclear magnetic resonance (NMR) is an attractive alternative to conventional viscosity measurements, as its measurements are fast, non-destructive and insensitive to technician error. Low field NMR is an accepted tool in conventional oil sandstone reservoirs, but has so far found only limited use in heavy oil and bitumen analysis. This work demonstrates that NMR can in fact be a valuable technology for heavy oil and bitumen formations like those in Alberta.
- North America > United States (0.93)
- North America > Canada > Alberta (0.48)
- Geology > Petroleum Play Type > Unconventional Play > Heavy Oil Play (1.00)
- Geology > Rock Type > Sedimentary Rock > Clastic Rock > Sandstone (0.54)
- Reservoir Description and Dynamics > Unconventional and Complex Reservoirs > Oil sand, oil shale, bitumen (1.00)
- Reservoir Description and Dynamics > Fluid Characterization (1.00)
- Production and Well Operations > Production Chemistry, Metallurgy and Biology > Downhole chemical treatments and fluid compatibility (1.00)
An Evaluation of the Application of Low Field NMR in the Characterization of Carbonate Reservoirs
Mai, An (University of Calgary) | Kantzas, Apostolos (University of Calgary)
Abstract Conventional reservoir analysis has always been an extensive process. In order to properly characterize a reservoir, cores and/or logs have to be obtained. Both core and log analysis is expensive and time consuming. NMR is an attractive alternative to these tools due to the fact that in theory, only one measurement is required. However, the conventional methods of interpreting NMR data only seem to work for simple sandstones. A new method of interpreting NMR data is required for complex porous structure such as carbonates. It was found that NMR can predict porosity that is similar to the values obtained by gas expansion. By using the NMR data at fully saturated and irreducible water saturation (Swi), a T2cutoff value was obtained for each sample that separates the bound and movable fluid signals. It was found that T2cutoff for carbonates is not 100 ms as is widely believed by many people who have analyze NMR in carbonates. A correlation for T2cutoff was found as a function of the size of the last peak and its geometric mean. A correlation was also found for Swi, which was a function of the size of the first and last peak. The Free Fluid and the mean T2 permeability models were evaluated. It was seen that the predictions from these models were not adequate. Another permeability model was developed, which is expressed in terms of the size of the first and last peak of the NMR spectrum obtained from the fully saturated sample. It was found that the correlation did a better job of predicting the permeability values. The new model has its own limitations, a method is currently being investigated to overcome these limitations. Despite these limitations, however, the new NMR permeability model provides better estimates of carbonate permeability than any other established methods. Introduction Conventional methods of analyzing the characteristics of carbonate reservoirs usually involve physically analyzing the core samples and/or analyzing the various logs collected from the wells. The important reservoir parameters that are usually investigated are porosity, permeability, and irreducible water saturation. These parameters will give an indication of the amount of hydrocarbons existing in the reservoir and how easy it is to recover them. In order to find these parameters using conventional core analysis, the cores samples taken from the wells first have to be cut and cleaned. The samples are then measured for porosity using one of many options available, and permeability is measured at the dry state. To find Swi, the core samples have to be saturated with brine and spun to the irreducible water condition. Carbonates generally have very tight pore structures, so the process of finding these parameters through core analysis is expensive and time consuming. To determine these reservoir parameters through log analysis, various logs have to be run. Due to limited vertical resolution, the presence of vuggy porosity might not be detected at all. Also, to estimate porosity from logs, lithology components are required. This causes difficulties in analyzing carbonate reservoirs in which the lithology is quite complex. Nuclear Magnetic Resonance (NMR) is a fairly recent application in reservoir study and it has garnered major successes in characterizing sandstone reservoirs. From a single NMR spectrum at the fully saturated conditions, porosity, irreducible water saturation and permeability of these reservoirs could be estimated. However, NMR application in carbonates has not been very successful.This is due to the fact that most earlier works assumed simple lithology and attempted to use the same models as for the sandstone reservoir. Thus the traditional method of interpreting NMR data can often lead to erroneous estimations in complicated porous media such as carbonates. This paper details an attempt to investigate porosity, permeability and irreducible water saturation by using NMR and Computed Tomography (CT) method to provide details on the pore structure of the carbonate samples.
- North America > United States > Texas (0.47)
- North America > United States > California (0.46)