Pore Fluid Content Research Articles

Diffusion of MRI and CT Contrast Agents in Articular Cartilage under Static Compression

Cartilage has a limited capacity for self-repair and focal damage can eventually lead to complete degradation of the tissue. Early diagnosis of degenerative changes in cartilage is therefore essential. Contrast agent-based computed tomography and magnetic resonance imaging provide promising tools for this purpose. However, the common assumption in clinical applications that contrast agents reach steady-state distributions within the tissue has been of questionable validity. Characterization of nonequilibrium diffusion of contrast agents rather than their equilibrium distributions may therefore be more effective for image-based cartilage assessment. Transport of contrast agent through the extracellular matrix of cartilage can be affected by tissue compression due to matrix structural and compositional changes including reduced pore size and fluid content. We therefore investigate the effects of static compression on diffusion of three common contrast agents: sodium iodide, sodium diatrizoate, and gadolinium diethylenetriamine-pentaacid (Gd-DTPA). Results showed that static compression was associated with significant decreases in diffusivities for sodium iodide and Gd-DTPA, with similar (but not significant) trends for sodium diatrizoate. Molecular mass of contrast agents affected diffusivities as the smallest one tested, sodium iodide, showed higher diffusivity than sodium diatrizoate and Gd-DTPA. Compression-associated cartilage matrix alterations such as glycosaminoglycan and fluid contents were found to correspond with variations in contrast agent diffusivities. Although decreased diffusivity was significantly correlated with increasing glycosaminoglycan content for sodium iodide and Gd-DTPA only, diffusivity significantly increased for all contrast agents by increasing fluid fraction. Because compounds based on iodine and gadolinium are commonly used for computed tomography and magnetic resonance imaging, present findings can be valuable for more accurate image-based assessment of variations in cartilage composition associated with focal injuries.

Poro-viscoelasticity modelling based on upscaling quasistatic fluid-saturated solids

In this paper, quasistatic models are developed for the slow flow of compressible fluids through porous solids, where the solid exhibits fading memory viscoelasticity. Problems of this type are important in practical geomechanics contexts, for example, in the context of fluid flow through unconsolidated reservoir sands and of wellbore deformation behaviour in gas and oil shale reservoirs, all of which have been studied extensively. For slow viscous fluid flow in the poro-viscoelastic media we are able to neglect the dynamic effects related to inertia forces, as well as the dissipation associated with the viscous flows. This is in contrast to the vast body of work in the poro-elastic context, where much faster flow of the viscous fluids may give rise to memory effects associated with microflows in pores of the solid media. Such problems have been treated extensively in both the dynamic and quasistatic cases. We are taking a specific type of the porous medium subject to slow deformation processes possibly inducing moderate pressure gradients and flow rates characterised by negligible inertia effects. As the result of homogenisation of such a two-phase medium, we observe the fading memory behaviour in the Biot modulus which controls the pressure increase due to skeleton macroscopic deformation and pore fluid content. Although our derivation leads to a result which is consistent with the formal phenomenological approach proposed by Biot (J Appl Phys 23:1482–1498, 1962), we offer the reader more insight into the structure of the poro-viscoelastic constitutive relations obtained; in particular, we can show that the Biot compressibility evolves in time according to the creep function while the skeleton stiffness is driven by the relaxation function.

3D CSEM modeling and time-lapse sensitivity analysis for subsurface CO2 storage

Monitoring a time-lapse geophysical anomaly due to variation in the pore-fluid contents of a subsurface reservoir is critical for further development and management. However, it may be difficult to detect the changes in P-wave responses beyond a certain level of saturation. A comprehensive 3D finite-difference time domain (FDTD) forward modeling, based on idealized subsurface resistivity structures, demonstrates the possibility of marine controlled-source electromagnetic (CSEM) surveying to monitor the movement of subsurface [Formula: see text] storage. We focused on CSEM sensitivity studies with respect to variations in geometry and/or saturation of [Formula: see text] storage, evaluation of the effects of reservoir depths and lithology, and detection of [Formula: see text] leakage from the main storage. A 100% lateral expansion from the initial diameter (1500 m) of a typical [Formula: see text] plume with thickness and resistivity of 100 m and 80 Ωm, respectively, at 850 m below seafloor, results in 41% electric field (E-field) magnitude increase at 2500 m source-receiver offset for 0.5 Hz source frequency. In comparison, a 300% vertical expansion of a 50 m thick plume with diameter and resistivity of 2500 m and 80 Ωm, respectively, gives only a 7% E-field magnitude anomaly. An increase of the aspect ratio of a [Formula: see text] plume with diameter and thickness of 1750 and 130 m, respectively, by 110%, without volumetric change, results in a 20% E-field magnitude increase. The E-field magnitude differences due to [Formula: see text] saturation change by 20% in clay-rich (10% clay) and clean reservoirs are almost identical; thus, a time-lapse anomaly in a clay-rich reservoir might be detectable. A gradual inverse variation of offset and frequency can differentiate the responses of a 50 m thick shallow [Formula: see text] accumulation, 200 m below the seafloor, from the main [Formula: see text] plume at 850 m below the seafloor and allow for early warning of [Formula: see text] leakage.

Petrophysical Seismic Inversion over an offshore carbonate field

The main objective of this project was to evaluate the ability to derive petrophysical properties like porosity from pre-stack seismic data in a carbonate environment. We apply a direct petrophysical inversion technique to an offshore carbonate reservoir. Starting from an initial geological model in depth and a number of carefully conditioned seismic angle stacks, we derive a detailed 3-D model of the porosity and hydrocarbon saturation matching the observed seismic data. We use a well-calibrated Petro-Elastic Model (PEM) to link the petrophysical properties to the seismic velocities. We compare inversion results obtained using the Xu-Payne and T-matrix PEMs which both account for carbonate pore geometry, lithology, porosity and fluid content but have different elastic sensitivity to fluid saturations. The inverted results provide detailed images of the spatial variations of porosity and fluid content across the reservoir interval. Predicting absolute saturation values is more difficult, as saturation estimation is strongly dependent on the choice of PEM.

Quantitative analysis of seismic response to total organic content and thermal maturity in shale gas plays

Although shales constitute about 75% of most sedimentary basins, the studies dealing with their seismic response are relatively few, particularly for the organic rich shale gas. Mapping distribution of shale gas and identifying their maturation level and organic carbon richness is critically important for unconventional gas field exploration and development. This study analyses the sensitivity of acoustic and elastic parameters of shales to variations in pore fluid content. Based on the effective medium theory a rock physics model has been made by inversion of the shale stiffness tensor from sonic, density, porosity and clay content logs. Due to the lack of a generally agreed upon fluid substitution model for shale, a statistical approach to Gassmann’s Model using effective porosity in the near boundary conditions, has been developed to account for shale. Fluid substituted logs—for a variety of maturation levels—and gas saturations were generated and used to make the layered earth models. AVO and seismic forward modelling were performed using the rock physics modelled and the fluid substituted logs on layered models. As part of seismic forward modelling, simultaneous inversion is performed for each model to generate P-impedance, S-impedance and density volumes. The sensitivity of the models were analysed by histogram, cross plotting, cross section highlighting, and body checking techniques. This study showed a dramatic hydrocarbon content effect—specifically gas—in the seismic response of shales.

Redevelopment of the Cardium Formation by Use of Fractured Horizontal Wells

This article, written by Assistant Technology Editor Karen Bybee, contains highlights of paper SPE 137737, ’Re development of the Cardium Formation Using Fractured Horizontal Wells: Res er voir-Engineering Perspectives and Early Case Histories,’ by E.N. Omatsone, M.A. Bagheri, SPE, and C.M.F. Galas, SPE, Sproule Associates; B. Curtis, Bonterra Energy; and K. Frankiw, Midway Energy, originally prepared for the 2010 CSUG/SPE Canadian Unconventional Resources & International Petroleum Conference, Calgary, 19-21 October. The paper has not been peer reviewed. The full-length paper presents a brief review of the historical performance of vertical wells in the low-reservoir-quality areas of the Cardium formation and describes the effect of placing multistage-fractured horizontal producers in these areas. The paper deals with the redevelopment of the Cardium formation from a primary-recovery perspective only, with a focus on the fringe areas around the supergiant Pembina field, as well as the development of the largely untapped resource in the A Lobe of the Cardium in the Garrington/Caroline areas. Introduction The Cardium formation is regionally extensive, spanning an area of nearly 150 townships in central/southern Alberta. The formation has been described as a clastic wedge that prograded into the western interior seaway during Turonian-Coniacian time. Many sedimentological responses identified within the formation indicate that the sand accumulation took place in muddy and sandy inner- and outer-shelf, shoreface, lagoonal, tidal, estuarine, and coastal-plain settings. This wide variety of depositional environments resulted in a diversity of lithofacies, multiple disconformities, paraconformities, and diastems of varying lateral extents. The predominant rock types in the Cardium are mudstone and sandstone with small, but important, conglomerate fractions. The Cardium deposits formed a series of stratigraphic traps, the largest of which is the supergiant Pembina field in central Alberta. Cardium reservoirs and pools have been found at depths ranging between 1200 and 2800 m and typically contain light, sweet oil with varying amounts of dissolved gas. A number of rich-gas pools also can be found in the Cardium formation. Operators who target the Cardium formation frequently are the beneficiaries of excellent core data, as a result of the standard industry practice of the 1950s through the 1980s. In the broader Pembina area, the Cardium exhibits exceptional log resolution because of its relatively shallow depth of burial. Many of the logs in the Garrington/Caroline area are of an older vintage and of generally poorer resolution. The abundance of core-plug, well-log, and production-performance data from the more than 10,000 vertical wells that have targeted the Cardium allows for high-quality petrophysical analysis and detailed geological mapping. Some operators have begun to use 3D-seismic amplitudes and other geophysical attributes to study the reservoir quality and pore-fluid content in various portions of the Cardium.

Mechanical characterization of small shale samples subjected to fluid exposure using the inclined direct shear testing device

The mechanical strength, elastic moduli, and other properties of shale are known to be highly sensitive to any variation in pore fluid content and pore fluid chemical composition. To date, all existing rock mechanics testing procedures and studies attempting to quantitatively quantify these changes employ standard methods and techniques, i.e., shale testing under hydrostatic confinement, triaxial tests, or direct shear tests, which require very long fluid circulation time due to the intrinsic low hydraulic permeability and low solute diffusivity of shale rocks and large sample size recommended by these conventional methods. Moreover, standard-size samples for conventional rock testing methods are not always available, and the use of non-conventional size samples is sometimes required. In this work, shale testing and results on rock sample the size and shape of a stack of a few pennies are presented. The inclined direct shear test, an innovative patent-pending testing method for small and thin rock specimens, has been developed to facilitate mechanical strength characterization under variable confining pressure, with tested material exposed to different fluids at any desired exposure time, while dynamic elastic moduli can be simultaneously monitored as functions of applied stress state. This device has been compared to standard triaxial test with excellent results. Practical applications using the inclined direct shear testing device (IDSTD TM) for three shale rocks of different natures are also presented herein.

Reservoir prediction using pre-stack inverted elastic parameters

This is a case study of the application of pre-stack inverted elastic parameters to tight-sand reservoir prediction. With the development of oil and gas exploration, pre-stack data and inversion results are increasingly used for production objectives. The pre-stack seismic property studies include not only amplitude verse offset (AVO) but also the characteristics of other elastic property changes. In this paper, we analyze the elastic property parameters characteristics of gas- and wet-sands using data from four gas-sand core types. We found that some special elastic property parameters or combinations can be used to identify gas sands from water saturated sand. Thus, we can do reservoir interpretation and description using different elastic property data from the pre-stack seismic inversion processing. The pre-stack inversion method is based on the simplified Aki-Richard linear equation. The initial model can be generated from well log data and seismic and geologic interpreted horizons in the study area. The input seismic data is angle gathers generated from the common reflection gathers used in pre-stack time or depth migration. The inversion results are elastic property parameters or their combinations. We use a field data example to examine which elastic property parameters or combinations of parameters can most easily discriminate gas sands from background geology and which are most sensitive to pore-fluid content. Comparing the inversion results to well data, we found that it is useful to predict gas reservoirs using λ, λρ, λ/µ, and K/µ properties, which indicate the gas characteristics in the study reservoir.

Attenuation anisotropy and the relative frequency content of split shear waves

The variation of frequency-dependent seismic wave attenuation with direction (attenuation anisotropy) contains additional information to that contained in velocity anisotropy. In particular, it has the potential to distinguish between different mechanisms that can cause velocity anisotropy. For example, aligned fracturing might be expected to cause measurable velocity and attenuation anisotropy, while preferred crystal orientation leads to significant velocity anisotropy but may cause only small amounts of attenuation. Attenuation anisotropy may also contain useful information about pore-fluid content and properties. We present a methodology for analysis of attenuation anisotropy, and apply it to a microseismic data set previously analysed for shear-wave splitting by Teanby (2004). Attenuation anisotropy values obtained show a temporal variation which appears to correlate with the temporal variation in the velocity anisotropy. The comparison of the relative frequency content of fast (S1) and slow (S2) split shear waves is a convenient method for examining seismic attenuation anisotropy. Provided that S1 and S2 initially have the same spectral colouring, that no spectral distortion is introduced by the differences between receiver responses of geophone components, and that spectral distortion due to background noise can be ignored or corrected for, we can attribute any differences in their frequency content to attenuation anisotropy. Attenuation anisotropy, where present, should be detected by the different (approximately orthogonal) polarizations of S1 and S2 as they pass through the anisotropic medium. In the presence of attenuation anisotropy S1 and S2 should experience different levels of frequency-dependent attenuation. We quantify the differential attenuation of S1 and S2 using a scheme based on a spectral ratio method. We present results from a microseismic data set acquired in an abandoned oil well at Valhall, a North Sea oil field. The results are surprising in that sometimes the slower arrival, S2, is richer in high frequencies than the faster, S1. This appears to be contrary to results predicted by theoretical crack models for attenuation anisotropy (e.g. Hudson 1981). The mechanism responsible for these observations is not clear. Our differential attenuation attribute correlates with the angle between the strike of the inferred initial shear-wave source polarization and the fast shear-wave polarization, which suggests that the split shear wave with the larger amplitude is preferentially attenuated. Our attribute also correlates with the event backazimuth, and the minimum percentage anisotropy.

Low-cost reservoir tomographs of electrical resistivity

The geophysics we describe here will sound different from what you have heard before, because it is different. It uses electric fields instead of seismic waves. It is not designed for exploration. It is a distant cousin of cross borehole seismic tomography, although it is quite different in terms of its application and results. Probably the most curious aspect is that it doesn't chase the holy grail of geophysics—high resolution. What good could possibly come from a low-resolution, electrical geophysical tool? The answer is found in the paradigm gradually finding favor by oil executives and reservoir engineers: while finding and exploiting large new fields is important for long-term growth, improving recovery efficiency for existing resources also makes sense because developing a new field is increasingly expensive. As a result, secondary recovery methods are receiving increasing attention. This shift in view requires a parallel shift in geophysics. Now geophysics needs to deliver useful information about field production using low-cost, long-term monitoring techniques that have minimum impact on production operations. Electrical resistance tomography (ERT) is ideally suited to these new goals. ERT is a method for tomographically reconstructing the electrical resistivity distribution in the subsurface using an array of electrodes. Typically, current is driven between two of the electrodes and the resulting voltage distribution is measured on the remaining electrodes. Repeating this with other pairs of current electrodes in the array makes it possible to sample the subsurface electrical properties in a manner that allows calculation of the spatial distribution of those properties. The electrical properties depend strongly on pore fluid content. Consequently, ERT is especially good at giving information on the movements of oil, water, and gas—the principal fluids of interest in a petroleum reservoir. An important aspect of this method is that the oil well casings themselves are used as …

Surface-Gravity Monitoring of the Gas Cap Water Injection Project, Prudhoe Bay, Alaska

Summary Modeling and field-test surveys indicate that time-differenced surface gravity can be used to successfully monitor the Gas Cap Water Injection (GCWI) Project at Prudhoe Bay, Alaska. Simulation results have shown that more than 95% of the injected water can be accounted for, including reasonable assumptions concerning the noise level in the measurements. The flood front can be reliably detected within 2,000 to 3,000 ft for the Prudhoe Bay reservoir that is buried at 8,200 to 8,800 ft true vertical depth (TVD). The world's first 4D surface-gravity surveillance of a water-flood is being implemented at Prudhoe Bay, Alaska. This monitoring technique is an essential component of the surveillance program for the approved Gas Cap Water Injection Project (GCWI) at Prudhoe Bay. A major factor in the approval of the waterflood was to show that water movement could be monitored economically with a very limited number of wells. Conventional monitoring techniques would have been cost-prohibitive because of the requirement for drilling numerous new surveillance wells. Modeling studies indicate that density changes associated with water replacing gas can be detected with high-resolution surface-gravity measurements. Field tests at Prudhoe Bay have demonstrated that sufficiently accurate gravity data can be obtained. This paper will discuss both inverse modeling of time-differenced gravity maps and four test surveys that have been completed to perfect the gravity-measurement technique. Forward and inverse gravity modeling were carried out on a suite of reservoir simulations of the GCWI. Differences in the gravity field with time reflect changes in the reservoir densities, which in turn reflect pore-fluid content. A constrained least-squares method was used to invert synthetic gravity data for the subsurface density distribution. The modeling procedure has been formulated to allow testing for sensitivity to gravity-sampling patterns, noise, and various constraints on model parameters such as density, total mass, and moment of inertia. These simulation results have shown that more than 95% of the injected water can be accounted for in the inverse model. These estimates include reasonable assumptions concerning the noise level in the measurements of both the gravity data and the location data using the Global Positioning System (GPS). The average flood front can be reliably detected within 2,000 to 3,000 ft for the Prudhoe Bay reservoir that is buried at 8,200 to 8,800 ft TVD. Time-differenced surface-gravity and GPS data were gathered over the Arctic Ocean in typical winter conditions (−40°F) accurately enough to monitor the waterflood (gravity =±10 μGal and GPS = ±1 cm elevation; a μGal is approximately one-billionth of the Earth's normal gravity).

Case study: AVO analysis in a high-impdeance Atoka Sandstone (Pennsylvania), North Arkoma Basin, McIntosh County, Oklahoma

The variation of reflection coefficients with source-to-receiver spacing in mul-tioffset seismic data is known to contain information about the lithology and pore-fluid content of subsurface rocks. However, such analysis is particularly challenging for thin, high-impedance reservoirs. In such instances, a key com-ponent of AVO analysis is a methodol-ogy for response calibration so that fluid properties can be interpreted vertically and laterally away from a borehole with a high degree of confidence.

Recent advances in seismic lithologic analysis

An objective of seismic analysis is to quantitatively extract lithology, porosity, and pore fluid content directly from seismic data. Rock physics provides the fundamental basis for seismic lithology determination. Beyond conventional poststack inversion, the most important seismic lithologic analysis tool is amplitude‐variation‐with‐offset (AVO) analysis. In this paper, I review recent progress in these two key aspects of seismic lithologic analysis.

AVO examples of long-offset 2-D data in the Gulf of Mexico

For more than 17 years, AVO has been a primary tool for predicting a reservoir's rock type and pore-fluid content. However, the success of an AVO interpretation (recognition and validation of an anomaly) is constrained by the rock properties of the reservoir and its surrounding media. Class 3 and 4 anomalies are recognized as amplitude bright spots on stack data, and pore-fluid prediction is routinely accomplished by anomaly/background amplitude analyses. For Class 2 anomalies, AVO interpretation of prestack data is often needed just to recognize potential reservoirs. Finally, AVO interpretation in Class 1 environments is difficult because hydrocarbons don't yield bright spots or amplitude brightening with source-receiver offset. In short, success in recognizing an anomaly and validating its composition is best for Class 3 and 4 environments and poorest for Class 1.

Shear hysteresis of rock at intermediate strains

Rocks with appropriate microsctructure are nonlinear with hysteresis in the strain range 10-6 to 10-3 while showing little permanent damage during deformation. Nonlinear effects alter strong motions produced by earthquakes and explosions and may lead to new methods for relating the mechanical properties of rock to microstructure and transport properties. Results of laboratory torsion experiments will be presented to demonstrate that various nonlinear responses appear when granite and sandstone samples are driven in harmonic motion at low frequencies with increasing amplitudes. Modulus reduction, amplitude-dependent attenuation and harmonic generation occur and depend on microstructural parameters, including microfracture density and pore fluid content. Friction and adhesion at internal surfaces and the deformation of fluid phases in pores all play a role in these observed phenomena. Numerical constitutive models which include micromechanics are being developed to simulate nonlinear behavior for comparison with experiment. [Sponsored by OBES geosciences and performed under the auspices of the U. S. DOE by LLNLL under Contract W-7405-ENG-48.]

Issues in rock physics and implications for DHI interpretation

Seismic techniques for direct hydrocarbon indication rely on the changes in seismic character which accompany changes in pore fluid content. Interpretation and modeling of direct hydrocarbon indicators (DHIs) require an understanding of the factors affecting seismic velocities and reflection coefficients which are, in turn, dependent on pore fluid properties, rock frame properties, and fluid substitution within a given rock frame. Recent developments in rock physics have greatly increased our general understanding in these areas but have also revealed complications that require further research.

Seismic velocities and inferred porosities in the accretionary wedge sediments at the Cascadia margin

Large offset multichannel seismic reflection data from the subduction zone margin off Vancouver Island define the geometry, internal structure, and deformation style of the Cascadia accretionary prism. A very detailed seismic velocity analysis has been performed to quantitatively assess the velocity structure and thus to infer porosity variations and pore fluid expulsion across the deformation front. Within the sediments of Cascadia Basin approaching the deformation front, and within the frontal thrust zone of the accretionary prism, velocities increase landward probably as a result of sediment consolidation associated with horizontal compression. A remarkable conclusion is that more than one third of the initial pore fluid content of the incoming sediments is lost by the time they are incorporated into the wedge. In contrast, a pronounced velocity decrease is evident in the lower slope region 15–20 km landward of the deformation front where the wedge sediment thickness is more than doubled compared with the section in Cascadia Basin. The low velocity is explained by underconsolidation resulting from rapid horizontal shortening and vertical thickening of the sediment column, accommodated by displacements along thrust faults or by distributed deformation. As interred from the velocity data, sediment porosities are high in this lower to midslope region of the wedge. The thickening of the wedge results in sediment elements being moved to greater depths landward with little porosity loss and velocity change. In the rapidly thickening section the overburden load stress increases faster than the sediments can respond by fluid expulsion and overpressures likely result.

Petrophysical imaging using AVO

Seismic lithology is the process by which rock properties—such as lithology, porosity, and pore fluid content—are determined by analysis of seismic and other data. I emphasize other data because the seismic method is limited in what can be achieved in a vacuum, but can be remarkably robust when combined with other information and constrained by geologically reasonable assumptions. I define “petrophysical imaging” as a seismic lithology method which does not attempt to recover absolute rock properties but rather involves the construction of an image of subsurface rock property variation. For example, for direct hydrocarbon indication, absolute rock properties need not be determined, only the deviation from background nonpay behavior is required.

A Reformation of the Equations of Anisotropic Poroelasticity

The constitutive equations of linear poroelasticity presented by Biot (1955) and Biot and Willis (1957) extended the description of rock behavior into the realm of saturated porous rocks. For isotropic material behavior, Rice and Cleary (1976) gave a formulation which involved material constants whose physical interpretation was particularly simple and direct; this is an aid both to their measurement and to the interpretation of predictions from the theory. This paper treats anisotropic poroelasticity in terms of material tensors with interpretations similar to those of the constants employed by Rice and Cleary. An effective stress principle is derived for such anisotropic material. The material tensors are defined, rigorously, from the stress field and pore fluid content changes produced by boundary displacements compatible with a uniform mean strain and uniform pore pressure increments. Such displacements and pore pressure increments lead to homogeneous deformation on all scales significantly larger than the length scale of microstructural inhomogeneities. This macroscopic behavior is related to the microscopic behavior of the solid skeleton. The tensors which describe the microscopic behavior of the solid skeleton would be difficult, even impossible, to measure, but their introduction allows relationships between measurable quantities to be identified. The end product of the analysis is a set of constitutive equations in which the parameters are all measurable directly from well-accepted testing procedures. Relationships exist between measurable quantities that can be used to verify that the constitutive equations described here are valid for the rock under consideration. The case of transverse isotropy is discussed explicitly for illustration.

Pore fluid content and void ratio for marine sediments. Technical note : Shimizu, M Soils FoundV30, N3, Sept 1990, p124–128

Pore fluid content and void ratio for marine sediments. Technical note : Shimizu, M Soils FoundV30, N3, Sept 1990, p124–128