Measurements of electrical capacitance in the flow of reservoir fluid with gas bubbles

This study examines the displacement of non-Newtonian fluid invasion in naturally fractured reservoirs (NFR) by employing the evaluated diffusivity solution proposed by Keshavarz, M., & Moreno, R. B. Z. L. (2023)1,for a comprehensive quantitative analysis. The solution is capable of considering not only drilling fluid pseudo-plasticity throughout the fractured but also the matrix system under constant wellbore pressure assumptions. The effects of non-Newtonian fluid parameters and NFR characteristics on fluid flow, leak-off phenomenon, and cumulative volume are examined. The developed solution generates type-curves for quantitative analysis, it validated by field data of loss measurements in a fractured well in the Gulf of Mexico. Parametric analysis reveals that drilling fluid pseudo-plasticity significantly impacts cumulative volume and ROI (radius of invasion) in NFRs with higher differential pressure, leak-off (particularly at earlier times), and larger fracture apertures. Additionally, the procedure allows operators to determine the ROI for equivalent starting and ending times of the transient period. The proposed solution, applicable to well-completion, enhanced oil recovery (EOR) processes, NFR characterization, and drilling operations, facilitates quantitative analysis of reservoir properties and cumulative volume in NFRs. It also assists operators in optimizing drilling fluid rheology in each period, reducing mud loss or enhancing volumetric sweep efficiency in polymer flooding cases. INTRODUCTION Non-Newtonian fluid flow through naturally fractured reservoirs (NFR) has received considerable attention over the last decades in both experimental and modeling research (Yi, 2004; Adenuga et al., 2019), as it controls important technological processes in petroleum and geotechnical engineering. The viscosity of such fluids has a non-linear relationship between shear stress and shear rate. Polymer solutions, heavy (waxy) crude oil, and drilling fluid are common examples of such fluids in petroleum; thus, they have been used for many years as fracturing agents, drilling fluids, and in some enhanced oil recovery processes (Ikoku & Ramey, 1979; Odeh & Yang, 1979; Garcia-Pastrana et al., 2017; Elkatatny et al., 2020; Albattat & Hoteit, 2021; Albattat et al., 2022; Pang et al., 2022). Even though their application is not novel, the subject of transient flow of non-Newtonian fluids in NFR is critical for improving the accuracy of total cumulative volume measurement and well testing (Ikoku & Ramey, 1979; Escobar et al., 2011; Dokhani et al., 2020). When fluids, flow through porous rocks, pressure behavior is affected by fluid rheology, reservoir architecture, reservoir type, and wellbore condition. NFR has been idealized as double porosity reservoir. The governing equation of the fluid for this type of reservoir is modeled considering flow regime and the geometry of the reservoir. While well test analysis involving the flow of Newtonian and non-Newtonian fluids in single and double-porosity reservoirs under wellbore constant rate has been extensively studied (Odeh & Yang, 1979; Da Prat, 1990; Dake, 2001; Escobar et al., 2011), none of these studies considered wellbore condition constant pressure, to measure non-Newtonian fluid rate and cumulative volume. The basic partial differential equation for newtonian fluid flow in NFRs are originally presented and solved under wellbore constant rate by Warren & Root et al (1963). The case was then studied and solved by Da Prat (1990), under constant wellbore producing pressure. Ikoku & Ramey et al. (1979) proposed a model characterizing homogeneous reservoirs with presence of a non-Newtonian (pseudoplastic) fluid. Olarewaju et al. (1992), was the first to develop an analytical solution for the transient behavior of dual-porosity formations containing a non-Newtonian pseudoplastic fluid. More than a decade later, Escobar et al. (2011) developed and successfully tested a methodology (based on solution presented by Olarewaju et al. 1992) for the interpretation of pressure tests in heterogeneous formations bearing a non-Newtonian fluid, based on the pressure and pressure derivative plot; as a result, they presented new equations for estimation of NFR parameters, which was later modified by Garcia-Pastrana et al (2017). Therefore, the focus of this research is on developing the applicability of evaluated solution presented by Keshavarz, M., & Moreno, R. B. Z. L. (2023) for the diffusivity model, which is solved under wellbore constant pressure and is applicable for cumulative fluid measurement. This evaluated solution has been applied as reference model due to considering dimensionless matrix contribution in pseudosteady-state inter-porosity transfer as the assumption of the dual porosity model. To the best of the Author's knowledge, no study has utilized an evaluated non-Newtonian dual porosity model to measure cumulative volume through NFR while taking leak-off into account. In this regard, evaluated dimensionless rate and cumulative volume solutions in Laplace domain were applied for radial flow of non-Newtonian pseudoplastic fluids in infinite dual-porosity reservoirs. The solutions were numerically inverted by Stehfest et al (1970) algorithm, followed by the formulation of dimensionless terms and generation of type curves to facilitate quantification of parameters in real time.

A new model of permeability to clarify the true behavior of fluid flow around producing wells is presented. A two-dimensional representation of fluid flow in the reservoir is inadequate in many ways. The direction of fluid flow in the reservoir is neither horizontal nor vertical, and consequently the traditional use of these two permeability components in determining fluid flow characteristics has been misleading. Rather, fluids flow from all parts of the reservoir and converge to the wellbore, a very small spot in a big reservoir. The flow pattern towards the wellbore takes a conical shape where the base of the cone at the reservoir boundary and the head is at the wellbore. In many cases, the flow reduces to the perforations which are even smaller "ports" compared to the huge reservoir. The need for a three-dimensional permeability becomes significant, and this term, complete with a technique for measuring it, is introduced here. A new method developed for determining the 3-D (conical) permeability presented and discussed. The proposed method is based on Darcy’s Law employed in a hemispherical scheme as the released gas flows from the probe through the sample in this pattern. The derivation of the model used along with the numerical technique utilized for solving are presented as well. Predictions of the model for air flow into a porous system are presented that appear to conform to the authors’ vision of fluid flow in petroleum reservoirs. This new 3-D (tapering) permeability term should enhance the accuracy of the models used to represent fluid flow in porous media.

By its nature, vaporization of atherosclerotic plaques by laser irradiation or spark erosion may produce a substantial amount of gas. To evaluate the effect of gas embolism possibly caused by vaporization techniques, air bubbles with diameters of 75, 150, or 300 microns, each in a volume of 2 microliters/kg, were selectively injected subproximal in the left anterior descending coronary artery of seven anesthetized pigs (28 +/- 3 kg). Systemic hemodynamics such as heart rate, left ventricular pressure and its peak positive first derivative, and mean arterial pressure did not change after air injection, whereas there was a minor change in peak negative first derivative of left ventricular pressure. After injection of air bubbles there was a maximal relative reduction of systolic segment shortening (SS) in the myocardium supplied by the left anterior descending coronary artery of 27, 45, and 58% for 75-, 150-, and 300-microns bubbles, respectively, and a relative increase of postsystolic SS (PSS) of 148, 200, and 257% for 75-, 150-, and 300-microns bubbles, respectively. Recovery of SS and PSS started after 2 min and was completed after 10 min. A difference in SS and PSS changes between different bubble size injections could be demonstrated. From this study it is clear that depression of regional myocardial function after injection of air bubbles could pass unnoticed on the basis of global hemodynamic measurements.

Summary URTeC 1618391 The physics of fluid flow in oil and gas reservoirs is determined by capillary forces and interfacial tension. Standard reservoir parameters are sufficient to understand fluid flow in many hydrocarbon productive reservoirs, but in other reservoirs additional information must be known to adequately determine the effects of capillary pressure and interfacial tension and to predict fluid flow. In conventional reservoirs the assumption is generally made that the reservoirs are in capillary pressure equilibrium. If this assumption is incorrect then our understanding of fluid flow in these reservoirs is invalid and we are dealing with unconventional reservoirs. Bennion, Thomas, and Ma (2000) recognized that there are reservoirs that were not in capillary pressure equilibrium. Post hydrocarbon uplift and erosion cause the water volumes to decrease in these reservoirs. Because of this deficit of water, if the reservoir is water wet and water is introduced to the well in the drilling or completion process, the reservoir will spontaneously imbibe water and water block the hydrocarbon pore network. If it is mixed wet but hydrophobic, then forced imbibition is required to get the water into the reservoir but the resulting water block is still very difficult to remove because it requires returning the reservoir to a non equilibrium state. The results of this relative permeability damage vary depending on the absolute permeability of the reservoir and the fluid saturations of the reservoir. The damaged hydrocarbon reservoir may flow nothing, a mixture of water and the hydrocarbons present, or even all water. The water produced can be greatly in excess of the water lost because it is water that is flowing from the water pore network in the reservoir that is no longer held in place by capillary forces because of the reservoir damage.

An accurate description of fluid flow is critical for the prediction of the productivity of shale gas reservoirs. In this paper, we present the current advances and a systematic summary on the fluid flow in shale gas reservoirs. First, shale pore structures, consisting of organic pores and inorganic pores ranging from nanoscale to micro‐scale, and reservoir fluids, including free gas, absorbed gas, and water, are systematically presented. Thereafter, multi‐physics flow phenomena motivated by scale effects, such as continuum flow, slip flow, transition flow, free molecular flow, and surface diffusion for gas, as well as the effective viscosity and slip boundary condition for water, are carefully summarized. Meanwhile, these flow mechanisms are discussed with molecular dynamics (MD) simulations and theoretical analysis. Subsequently, on the basis of upscaling approaches, including capillary bundle models, the lattice Boltzmann method (LBM), and pore network models (PNMs), fluid flow through heterogeneous shale matrix is reviewed and the influences of scale effects and pore structures are clarified. Additionally, shale gas well performance is discussed by combining the multiple transport mechanisms and a fracturing‐shut‐in‐flowback‐production process. Our review concluded that the fluid flow behaviour in shale gas reservoirs is a complex multi‐scale process accompanied by multi‐physical phenomena and multi‐fluid distributions. Keeping this in mind is helpful for predicting the shale gas production and recoverable gas resources. We expect this study can not only help by providing a better understanding of the fluid flow in shale reservoirs but also provide significant implications to address other multiphase flow processes.

The basic equations for the flow of gases, compressible liquids and incompressible liquids are derived and the full implications of linearising then discussed. Approximate solutions of these equations are obtained by introducing the concept of a disturbed zone around the well, which expands outwards into the reservoir as fluid is produced. Many important and well-established results are deduced in terms of simple functions rather than the infinite series, or numerical solutions normally associated with these problems. The wide range of application of this approach to transient radial flow problems is illustrated with many examples including; gravity drainage of depletion-type reservoirs; multiple well systems; well interference. Introduction A large number of problems concerning the flow of fluids in oil reservoirs have been solved by both analytical and numerical methods but in almost all cases these solutions have some disadvantages - the analytical ones usually involve rather complex functions (infinite series or infinite integrals) which are difficult to handle, and the numerical ones tend to mask the physical principles underlying the problem. It would seem appropriate, therefore, to try to find approximate analytical solutions to these problems without introducing any further appreciable errors, so that the physical nature of the problem is retained and solutions of comparable accuracy are obtained. One class of problems will be considered in this paper, namely, transient radial flow problems, and it will be shown that approximate analytical solutions of the equations governing radial flow can be obtained, and that these solutions yield comparable results to those calculated numerically and those obtained from "exact" solutions. It will also be shown that the restrictions imposed upon the dependent variable (pressure) are just those which have to be assumed in deriving the usual diffusion-type equations. The method was originally suggested by Guseinov, whopostulated a disturbed zone in the reservoir, the radius of which increases with time, andreplaced the time derivatives in the basic differential equation by its mean value in the disturbed zone. In this paper it is proposed to review the basic theory leading to the equations governing the flow of homogeneous fluids in porous media and to consider the full implications of the approximation introduced in linearising them. The Guseinov-type approximation will then be applied to these equations and the solutions for the flow of compressible and incompressible fluids, and gases in bounded and infinite reservoirs obtained. As an example of the application of this type of approximation, solutions to such problems as production from stratified reservoirs, radial permeability discontinuities; multiple-well systems, and well interference will be given. These solutions agree with many other published results, and in some cases they may be extended to more complex problems without the computational difficulties experienced by other authors. THEORY In order to review the basic theory from a fairly general standpoint it is proposed to limit the idealising assumptions to the minimum necessary for analytical convenience. The assumptions to be made are the following:That the flow is irrotational.That the formation is of constant thickness.Darcy's Law is valid.The formation is saturated with a single homogeneous fluid. SPEJ P. 225^

This paper is an analysis of the unsteady flow of a compressible fluid flowing radially to a well in a sand formation. The phenomenon of unsteady flow occurs as a result of fluid expansion. When the pressure in the formation is lowered, the fluids therein expand and the increase in volume imparts motion to the fluid which flows towards the region of lowest pressure in the formation. This process is continuous in the reservoir and extends further away from the well with increased production. By the ``equation of continuity,'' the solution for two specific cases of unsteady flow are derived. The first of these is that in which the fluid from a sand reservoir of limited size flows to a well in which the pressure at the level of the producing sand always remains constant. The variation of the pressure gradient, the rate of production, and the cumulative production with respect to time are given in Eqs. (11), (24), (29) and (30). The second case is that in which the flow of fluid to a well is such that the rate of production at the well is always constant. This case is derived by the assumption that the cylindrical body of sand, which is influenced by the well, is subject to a steady depletion of fluid, and in order that the rate remain constant at the well, fluid must flow into the reservoir from some extraneous source in increasing amounts. Eventually, however, the rate of flow of fluid into the reservoir becomes equal to the rate at which fluid is withdrawn from the well and steady flow is established in the sand. The equations for the pressure gradient and the decline of pressure at the well with respect to time are (39), (52) and (56).

Expiration of fossil fuels and climate irregularities directs the energy demands towards renewable energy sources for the energy supply in future. In this frame, geothermal energy gives a substantial contribution to the strategies of renewable-source based energy production. Efficiency of this component requires to develop new geothermal sites and to improve the performance of existing systems. The main contribution of geoscience is to optimize and characterize the potential of geothermal sites. One of the essential steps of reservoir characterisation is the understanding of fluid flow in the reservoir. Fluid flow in tectonic active areas is mainly controlled by fault zones. In this study, structural mapping and hydrogeological analysis is used to provide insights into the regional reservoir setup. Here, geohydrochemical analysis is performed to characterize fluid- and rock-composition and the interaction between fluids and rocks. On the other hand, numerical simulations are used to explain the role of fault hydraulic conductivity and fluid properties on temperature and pressure distribution in the study area. The study area is the high-enthalpy geothermal field Lahendong in Sulawesi-Indonesia. It hosts a producing geothermal power plant producing 80 MW of electricity. Geoscientific investigations in the Lahendong geothermal field have started early 1970s. However, the evolution and distribution of thermal fluids within the target area is still in debate. The present day conceptual model shows that the geothermal field consists of two sub-reservoirs separated by horizontally less permeable fault zones. Brine of low pH is predominantly seen in the north while moderate pH fluids exist in the south and east. Accordingly, production rates vary between the northern and southern parts by a factor of five. However, faults behave permeable sub-parallel to the strike. Therefore, hot springs arise mostly along or at junction of faults. Lahendong area is characterized by basaltic andesite, tuff and volcanic breccia. Detailed investigations on hydraulic conductivity of fault zones show that faults either act as fault-normal flow barriers due to sealing of the fault core, or as conductive pathways in the damage zone sub-parallel to the fault strike. The damage zone, especially in case of extensional faults, is characterized by fractures. The impermeable fault core is a barrier between one reservoir section, which is characterized by acidic water, considerable gas discharge, high productivity and strongly altered and fractured rocks and another section, which hosts pH-neutral waters, high temperatures and less altered rocks. Those reservoir conditions observed on-site have been converged in numerical hydrochemical models. The fault-controlled vertical and horizontal fluid flow is used to simulate different reservoir sections. Recharge and discharge in the model occurs along the faults. However, fluid flow is also influenced by fluid phase transition. Steam propagation at top of faults stimulates vertical fluid rise, because steam propagates faster due to lower density. Therefore, in case of 2-phase flow simulations, permeabilities have to be lower to satisfy same pressure and temperature conditions. The main contribution of this study is to show that systematically performed structural analysis helps to understand the fluid flow in geothermal reservoirs. It has been confirmed that the hydrotectonic concept combining the tectonic and hydrogeological information essentially improves the understanding of subsurface flow of thermal fluids, which is the basic source of geothermal power plants. This is crucial for site selection and smart drilling strategies, which supports a sustainable exploitation of the geothermal field avoiding risks, such as low-productive wells or the production of highly corroding waters. Results also guide reservoir management in case of a potential for field extension, as performed in Lahendong.

The low-permeability reservoirs are of heavy heterogeneity, low permeability, fine oil-water passages, strong resistance during flow, and the significant interaction between solid and liquid interfaces causes the flow of fluid in reservoir deviating from the Darcy’s law. There is no agreement on the interaction between the various factors in seepage process and the influence of seepage law. The boundary layer exists when liquid flow in micro-tubes and nano-tubes, and the boundary layer decreases with the increase of driving force, and the maximum value of boundary layer ratio is equal to 1. Based on the capillary boundal model and the boundary layer theory, a new exponential seepage model for low permeability reservoirs was proposed. Some experiments of water flow with different pressure gradient were carried out in low permeability cores with permeability of 4 to 8 milidarcy in natural rock cores from an oilfield in China, and the nonlinear model is of good agreement with the single-phase water flooding experiments of these cores. The results demonstrate that the physical meaning of each parameter of the new model is clear and it can be applied to describe the nonlinear characteristics of low permeability reservoirs. The large driving force can overcome disadvantages in the developments of low permeability reservoirs.

SUMMARY: Realizing the potential of geothermal energy as a cheap, green, sustainable resource to provide for the planet’s future energy demands that a key geophysical problem be solved first: how to develop and maintain a network of multiple fluid flow pathways for the time required to deplete the heat within a given region. We present the key components for micro-scale particle-based numerical modeling of hydraulic fracture, and fluid and heat flow in geothermal reservoirs. They are based on the latest developments of ESyS-Particle—the coupling of the lattice solid model (LSM) to simulate the nonlinear dynamics of complex solids with the lattice Boltzmann method (LBM) applied to the nonlinear dynamics of coupled fluid and heat flow in the complex solid-fluid system. The coupled LSM/LBM can be used to simulate development of fracture systems in discontinuous media, elastic stress release, fluid injection and the consequent slip at joint surfaces, and hydraulic fracturing; heat exchange between hot rocks and water within flow pathways created through hydraulic fracturing; and fluid flow through complex, narrow, compact and gouge- or powder-filled fracture and joint systems. We demonstrate the coupled LSM/LBM to simulate the fundamental processes listed above, which are all components for the generation and sustainability of the hot-fractured

A good understanding of the internal geometry of a reservoir is necessary for making realistic oil recovery forecasts. In answer to this need, software has been developed to generate 3D lithological images of a reservoir by using a geostatistical approach. Based on previous images, a petrophysical description is then obtained on a geologic mesh scale. And to perform flow simulation, petrophysical parameters must then be scaled up to reservoir mesh scale. This paper shows an application of the complete procedure of processing from geostatistical imaging to fluid flow modeling.

Void fraction measurements for vertical flow in a small diameter tube (9.53 mm) were taken using two non-intrusive capacitive void fraction sensors. The sensors were needed to measure the void fraction of water - air two-phase flow under normal gravity and microgravity conditions. Void fraction data were collected with: (1) a sensor having helical wound electrodes that was used to collect data under normal gravity and microgravity conditions, (2) a sensor having concave plate electrodes, used to collect data at normal gravity. This paper covers the calibration results for both sensors and some of the problems associated with the helical wound design. Nonlinearity in the helical sensor is addressed, with improvements shown in the concave plate sensor. Comparisons are made between the capacitive sensors, quick-closing valves and a gamma densitometer.

Summary Complex beds can significantly affect the flow of fluids in reservoirs. However, current simulators generally are not well-suited to model such flows, in part because they typically do not model permeability as a tensor quantity. This paper demonstrates the importance of treating permeability as a full tensor quantity in simulating flow through complex beds by considering two related problems. First, fluid flow through cross-stratified beds is studied. In this case, heterogeneities appear on the fine scale, and a scale-up procedure is required to model explicitly the effects of these beds. A general numerical procedure, which properly preserves the tensor nature of the effective permeability of such strata, is presented for this computation. The method is based on a finite-element solution of the fine-scale pressure equation with periodic boundary conditions imposed. Second, the modeling of flow through anisotropic, inclined reservoir beds is studied. It is shown that the commonly used techniques for modeling flow through such features, stratigraphic and horizontal layering, implicitly assume principal directions (or orientations) for the permeability tensor. With simple model problems, the differences between simulation results for different orientations of the permeability tensor and differences between results from horizontal and stratigraphic layering are quantified. These differences, which are substantial in the case of high reservoir dip and high anisotropy, emphasize the importance of a knowledge of the full permeability tensor in predicting flow through complex reservoir features.

Waterflooding has been an effective method for improving oil recovery process of Low-Permeability Reservoirs. Tight Low-Permeability reservoirs are characterized by natural fractures, hydraulic fractures, and induced fractures by water injection. These fractures may have a significant impact on process performance and ultimate recovery. The interaction between pre-existing natural fractures and the propagating fractures are critical factors affecting the complex fracture network. It is a great challenge to model accurately fluid flow due to the multi-scale nature of the problems and the strong coupling that exists between flow and mechanical behaviors. In this paper, a dynamic discrete Fracture modeling approach was developed and implemented which enabled integrated simulation of fracture network propagation, interactions between hydraulic fractures and pre-existing natural fractures, fracture fluid leak off and fluid flow in reservoir. We apply the Discrete Fracture Modeling (DFM) approach to represent large-scale fractures individually and explicitly. The model allows inclusion of the impact of stress regime on fluid flow in a discrete fracture network. This entails highly constrained unstructured gridding and construction of a connection (transmissibility) list of all neighboring cells. A methodology for modeling fracture propagation in length- and height-direction is presented with respect to poro- and thermo-elastic stresses acting on the fracture. The method was solved using the discrete fracture control volume method. Results were obtained in terms of saturation and pressure distribution for various fractured porous media. Comparisons for simulation results and well production performance show an excellent match. The new model allows us to better understand the multi-scale and multi-physics flow behavior caused by complex fracture system. Sensitivity studies by varying the production rate, pressure and fracture parameters could be conducted to provide guidance on optimizing production designs. The simulation results show that reservoir dynamic fractures play an important role in both direction and speed of water displacement fronts through tight low-permeability reservoirs. The oil recovery rate significantly depends on the fractures orientation and the rate of fracture growth. The proposed simulation method provides a useful tool for modeling the effect of fractures on waterflooding performance and can be used to optimize injection pressures and rates, water quality as well as well patterns for maximizing oil recovery.

"4D seismic reservoir monitoring" is the process of repeating 3D seismic surveys over a producing reservoir in time-lapse mode. It has a potentially huge impact in reservoir management because it is the first technique that may allow us to directly image dynamic reservoir processes such as fluid movement, pressure build-up, and heat flow in a reservoir in a true volumetric sense. However, its simple underlying concept is complicated by practical operational issues. These include having the right mix of business to justify a 4D seismic project, a favorable technical risk assessment and feasibility study, highly repeatable seismic acquisition survey design, careful high-resolution seismic data processing, and an ultimate reconciliation of 4D seismic images with independent reservoir borehole data and history-matched flow simulations. The practical difficulties associated with 4D seismic suggest that this new technology is not a panacea, but rather that it is an exciting emerging technology that requires very careful analysis to be useful. Introduction "4D seismic reservoir monitoring" is the process of repeating 3D seismic surveys over a reservoir in time-lapse mode to look for differences caused by production. The potential exists for dramatic benefits to reservoir management because it is the first technique that may allow us to directly image dynamic reservoir processes such as fluid movement, pressure build-up, and heat flow in a reservoir in a true volumetric sense. To understand this, let us review the seismic method, and then consider what advantages the time-lapse aspect of 4D seismic brings. In a single 3D seismic survey, seismic waves are generated by sources (dynamite, airguns, etc.) at or near the earth's surface. These source waves reflect off of subsurface seismic impedance contrasts, which are a function of rock and fluid compressibility, shear modulus and bulk density, and are recorded as they arrive back at the earth's surface. The recorded waves form the classic wiggle traces where high positive amplitude portions are often filled in on a black and white image to enhance visual contrast and show lateral continuity. A wave-equation imaging algorithm is applied to the recorded reflection data to create 3D seismic images of the reservoir rock and fluid property (seismic impedance) contrasts. 4D seismic analysis simply involves repeating the 3D seismic surveys and analyzing images in time-lapse mode, to monitor time-varying fluid-flow processes during reservoir production. 4D seismic has all the traditional benefits of 3D seismic, plus a major additional potential benefit that fluid-flow processes can be directly imaged. To first order, seismic images are sensitive to spatial contrasts in two distinct types of reservoir properties:non-time-varying static geology properties such as lithology, porosity, shale content; andtime-varying dynamic fluid-flow properties such as fluid saturation, pore pressure and temperature. Given a single 3D seismic survey, representing a single snapshot in time of the reservoir, the static geology and dynamic fluid-flow contributions to the seismic image are non-uniquely coupled and therefore difficult to separate unambiguously. For example, it may be impossible to distinguish an oil-water contact from a horizontal depositional boundary in a single seismic image. However, with 4D seismic surveys, examining the difference between time-lapse 3D seismic images allows the non-time-varying geologic contributions to cancel, resulting in a direct image of the time-varying changes caused by reservoir fluid flow. For example, an oil-water contact may move with time in a series of time-lapse seismic images, whereas a depositional boundary should not. In this way, the 4D seismic technique has the potential to image, in a large volume encompassing many wellbores, changes in fluid saturation, pore pressure and temperature during production. 4D seismic reservoir monitoring promises to add significant improvements in our ability to estimate saturation and pressure distributions from sparse well control and flow simulations. P. 449^