Evaluating feasibility of seismic fluid monitoring

ECLIPSE, FrontSim, MultiWave Array and RFT (Repeat Formation Tester) are marks of Schlumberger.

The parametric method is known for probabilistic estimation of hydrocarbon reserves (Smith, Hendry and Crowther, 1993). This analytical approach is not “black boxy” as compared to the Monte Carlo simulation. It uses common statistical information. More so, the relative impact of the input parameters is easily ranked to ascertain each individual’s contribution to the total uncertainty. This paper elaborates the use of the parametric approach to analyze the uncertainty associated with the effect of reservoir fluids on seismic properties. The outcome is compared with Monte Carlo simulation and deterministic techniques. A forward modeling algorithm based on fluid substitution procedure is employed in the study. The model assumes each reservoir fluid such as black oil, volatile oil, gas condensate, dry gas and water is saturated in the rock pores. The effect of these fluids on seismic properties such as compressional velocity, shear velocity, acoustic impedances is simulated with uncertainty. Moreover, saturation changes effect on these seismic properties in a two phase system is also studied. Beyond these, a relative impact analysis is carried out to know the individual input data’s contribution to the total uncertainty. Sandstone reservoir rock and fluid properties from laboratory are used for the analysis. Scale-up techniques are used to ensure consistency between laboratory and seismic scale data. The results from both parametric and Monte Carlo simulation showed a good agreement. The results showed a unique effect exhibited by each reservoir fluid on the seismic properties. This approach can assist in identifying reservoir fluids especially at in-situ conditions from the seismic results. The outcome also showed a similar observed result in the Wyllie plot of velocity versus fluid saturation changes. The prediction of saturation effect on seismic properties would enrich time-lapse reservoir monitoring in identifying unswept zones and aid in optimizing in-fill drilling.

SPE reservoir evaluation & engineering, 2016

This paper presents case studies focused on the interpretation and integration of seismic reservoir monitoring from several fields in conventional offshore and deepwater Niger Delta. The fields are characterized by different geological settings and developmentmaturity stages. We show different applications varying from qualitative to quantitative use of time-lapse (4D) seismic information. In the first case study, which is in shallow water, the field has specific reservoir-development challenges, simple geology, and is in phased development. On this field, 4D seismic, which was acquired several years ago, is characterized by poor seismic repeatability. Nevertheless, we show that because of improvements from seismic reprocessing, 4D seismic makes qualitative contributions to the ongoing field development. In the second case study, the field is characterized by complex geological settings. The 4D seismic is affected by overburden with strong lateral variations in velocity and steeply dipping structure (up to 40 ). Prestack-depth-imaging (PSDM) 4D seismic is used in a more-qualitative manner to monitor gas injection, validate the geologic/reservoir models, optimize infill injector placement, and consequently, enhance field-development economics. The third case study presents a deep offshore field characterized by a complex depositional system for some reservoirs. In this example, good 4D-seismic repeatability (sum of source-and receiver-placement differences between surveys, dSþdR) is achieved, leading to an increased quantitative use of 4D monitoring for the assessment of sand/sand communication, mapping of oil/water (OWC) front, pressure evolution, and dynamic calibration of petro-elastic model (PEM), and also as a seismic-based production-logging tool. In addition, 4D seismic is used to update seismic interpretation, provide a better understanding of internal architecture of the reservoirs units, and, thereby, yield a morerobust reservoir model. The 4D seismic in this field is a key tool for field-development optimization and reservoir management. The last case study illustrates the need for seismic-feasibility studies to detect 4D responses related to production. In addition to assessing the impact of the field environment on the 4D-seismic signal, these studies also help in choosing the optimum seismicsurvey type, design, and acquisition parameters. These studies would possibly lead to the adoption of new technologies such as broad-band streamer or nodes acquisition in the near future.

Subsurface formations with pore fluid pressure in excess of the hydrostatic pressure (geopressure) are encountered worldwide. Although there are a multitude of causes that can result in geopressure, under compaction due to rapid burial of sediments is the predominant cause of geopressure. Typically, if the loading process is rapid, fluid expulsion through compaction is severely retarded, especially in fine-grained sediments with low permeability such as silts or clays. This results in stress redistribution within the column-a greater proportion of the overlying weight of the sediments is borne by the fluids than when the sediments compact normally, causing a decrease in the stress acting on the rock framework. Dehydrating bound water from clays within shales further complicates this phenomenon as compaction proceeds with the depth of burial with increase in temperature. Geopressured formations pose significant threats to drilling safety, and the cost of mitigation, especially, in deepwater settings, is high, to the tune of $1.08 billion per year worldwide. Proper planning before drilling is key to lowering costs and increasing safety. In this regard, the role of seismic is of paramount importance. Seismic wave attributes (amplitude, velocity, coherency, etc.) are affected when stresses acting on the sedimentary column (effective or differential stress) are low. These attributes can be analyzed to obtain signatures of overpressure or lack of fluid transport over the geologic time-both qualitatively and quantitatively. Using the seismic signatures, zones of trapped fluids and pressured compartments can also be mapped prior to drilling. With either an analogue or a reliable lowfrequency velocity model, it is also possible to map fluid transport effects in the reservoir scale using seismic inversion techniques. In this paper, we illustrate how this process works using seismic data at various scales, from the low frequency reflection seismic at exploration frequency scales to those employed at well-logging scales. A rock-model-based approach especially suited for deepwater pore pressure imaging is introduced. It includes the effect of shale burial diagenesis, and uses the velocities derived from inversion of prestack seismic data. The procedure yields details of pre-drill pore pressure images with significant clarity as well as pressure versus depth profiles appropriate for drilling applications. In particular, prestack full waveform inversion yields Poisson's ratios that are useful not only for pressure and fracture gradient estimations but also for lithology and fluid identification. This technique is also applicable to identification of shallow water flow formations that pose drilling hazards in deep water. The procedure is illustrated with examples from several deep water basins.

SN Applied Sciences

One of the most common methods for determining elastic moduli of rocks is the acoustic velocity log. The elastic moduli of reservoir rocks are widely used in geomechanical modeling, borehole stability analysis, and hydraulic fracture design. In the carbonate reservoirs, the effect of the fluid type on the dynamic elastic modulus under high pressure conditions have rarely been investigated. Carbonate oil reservoirs are known for their heterogeneity and anisotropic nature. Therefore, it is a challenge to find a reliable correlation between the acoustic velocity and rock/fluid properties. In this paper, the acoustic velocities of several carbonate samples with a wide range of porosity and permeability from different oil reservoirs were measured under different confining and axial stresses. Our study shows that wettability of rock samples plays an important role in the acoustic velocities, particularly in tight pores. In addition, an increase in compressional velocity after saturation was reported. In order to fully understand the effect of fluid type, a new parameter [relative change of shear modulus (RCS)] is defined. Experimental results shows that strong water wet samples have higher RCS values rather than oil wet samples which means that the wettability of the carbonate rocks is one of the main important factors in dynamic elastic modulus.

Oil & Gas Science and Technology, 2003

-Caractérisation pétroacoustique des roches réservoirs pour les études de monitoring sismique. Mesure au laboratoire des paramètres de Hertz et de Gassmann-La production des gisements d'hydrocarbures, ou le stockage du gaz dans les couches géologiques, a toujours un effet direct sur le contenu en fluides et sur les pressions de pores, et, par conséquent, sur les propriétés sismiques des roches réservoirs. Dans cet article, nous présentons les méthodes de laboratoire permettant de mesurer l'effet des variations de pression différentielle et de fluide saturant sur les vitesses de propagation des ondes élastiques dans les roches réservoirs. L'effet de pression est facilement mesuré, au laboratoire, par l'intermédiaire du coefficient de Hertz, exposant de la fonction puissance liant la vitesse à la pression différentielle. Il est difficile d'estimer la représentativité des échantillons de carottes ayant subi la brutale relaxation de contrainte causée par le carottage. La comparaison statistique de résultats de mesures sur échantillons de surface et sur échantillons de carottes confirme la réalité de cet endommagement. Les valeurs mesurées au laboratoire sont souvent des valeurs par excès. Elles sont très utiles pour fixer des bornes supérieures à l'effet attendu de la pression différentielle. Cet effet est souvent négligeable dans de très nombreux réservoirs calcaires. Il peut être important dans des réservoirs gréseux peu profonds (stockages souterrains) ou surpressurisés. L'effet du fluide saturant est quantifié par la formule de Gassmann dont la validité est très généralement vérifiée par l'expérience. Pour utiliser cette formule, il faut connaître certaines caractéristiques élastiques de la roche. Ces modules peuvent être déterminés au laboratoire. Nous proposons une méthode originale et simple dans son principe, basée sur la mesure expérimentale de la relation quasi linéaire prédite par la théorie de Biot-Gassmann, entre le module d'incompressibilité K sat de la roche saturée et le module d'incompressibilité K fl du fluide saturant. Dans les grès, lors des expériences de substitution, il faut utiliser des liquides ne perturbant pas les minéraux argileux (et les feldspaths altérés). Hormis le cas des grès parfaitement propres, il est alors très préférable de conserver une saturation irréductible en saumure (S wi) et donc de travailler en saturation diphasique (saumure/hydrocarbures). Dans les calcaires, d'où l'argile est le plus souvent absente, les expériences de substitution de fluides sont facilitées par la possibilité de pratiquer des balayages monophasiques par des liquides de module d'incompressibilité très varié. L'avantage induit par cette réelle facilité expérimentale est malheureusement diminué par la difficulté de traitement des signaux qu'entraîne le phénomène de

Earth-Science Reviews

Since the advent of seismic imaging techniques, the dream of geophysicists has been to identify the fluid effect and be able to accurately map hydrocarbon from the brine within a target reservoir. The usage of bright spots (strong reflection amplitudes) as an indicator of hydrocarbon was the earliest recognition of the direct role played by the pore fluids in seismic signatures. Further development of new techniques had a strong correlation with the increase in computing power and advances in seismic acquisition and processing techniques. In this review, we touch upon the relevant theory developed more than 100 years ago, and then review the methods developed over five decades leading to the quantitative interpretation of seismic data for fluid detection. We also carried out a case study to compare selected fluid identification methods applied to a complex reservoir within an oil and gas field in the Barents Sea. The impedance-based methods "CPEI-Curved Pseudo-elastic Impedance" and "LMR-Lambda-Mu-Rho" inversion provided better results compared to other techniques, highlighting the critical influence anomalous lithologies have on such screening attributes.

2007

In this paper, we present an example of using PP and PS converted-wave data recorded by digital MEMS (micro-eletro-mechanical-system) to evaluate a fractured tight gas reservoir from the Xinchang gas field in Sichuan China. For this, we analyze the variations in converted shear-wave splitting, Vp/Vs ratio and PP and PS impedance, as well as other attributes based on absorption and velocity dispersion. The reservoir formation is tight sandstone, buried at a depth of about 5000m, and the converted-wave data reveal significant shear-wave splitting over the reservoir formation. We utilize a rotation technique to extract the shear-wave polarization and time delay from the data, and a small-window correlation method to build time-delay spectra that allow the generation of a time-delay section. At the reservoir formation, the shear-wave time-delay is measured at 20ms, about 15% shear-wave anisotropy, correlating with the known gas reservoirs. Furthermore, the splitting anomalies are consistent with the characteristics of other attributes such as Vp/Vs ratio and P-and S-wave acoustic and elastic impedance. The P-wave shows consistent low impedance over the reservoir formation, whilst the S-wave impedance shows relatively high impedance. The calculated gas indicator based on absorption and velocity dispersion yields a high correlation with the gas bearing formations.

Geophysical Prospecting, 2002

Interpretation, 2013

The Cranfield field in southwest Mississippi has been under continuous CO 2 injection by Denbury Onshore LLC since 2008. Two 3D seismic surveys were collected in 2007 and 2010. An initial 4D seismic response was characterized after three years of injection, where more than three million tons of CO 2 remain in the subsurface. This interpretation showed coherent seismic amplitude anomalies in some areas that received large amounts of CO 2 but not in others. To understand these effects better, we performed Gassmann substitution modeling at two wells: the 31F-2 observation well and the 28-1 injection well. We aimed to predict a postinjection saturation curve and acoustic impedance (AI) change through the reservoir. Seismic volumes were cross-equalized, well ties to seismic were performed, and AI inversions were subsequently carried out. Inversion results showed that the change in AI is higher than Gassmann substitution predicted for the 28-1 injection well. The time-lapse AI difference predicted by the inversion is similar in magnitude to the difference inferred from a time delay along a marker horizon below the reservoir.

Geophysical Journal International, 2012

In this work, we analyse the role of permeability on the seismic response of sandstone reservoirs characterized by patchy gas-water saturation. We do this in the framework of Johnson's model, which is a generalization of White's seminal model allowing for patches of arbitrary geometry. We first assess the seismic attenuation and velocity dispersion characteristics in response to wave-induced fluid flow. To this end, we perform an exhaustive analysis of the sensitivity of attenuation and velocity dispersion of compressional body waves to permeability and explore the roles played by the Johnson parameters T and S/V , which characterize the shape and size of the gas-water patches. Our results indicate that, within the typical frequency range of exploration seismic data, this sensitivity may indeed be particularly strong for a variety of realistic and relevant scenarios. Next, we extend our analysis to the corresponding effects on surface-based reflection seismic data for two pertinent models of typical sandstone reservoirs. In the case of softer and more porous formations and in the presence of relatively low levels of gas saturation we observe that the effects of permeability on seismic reflection data are indeed significant. These prominent permeability effects prevail for normal-incidence and non-normal-incidence seismic data and for a very wide range of sizes and shapes of the gas-water patches. For harder and less porous reservoirs, the normal-incidence seismic responses exhibit little or no sensitivity to permeability, but the corresponding non-normalincidence responses show a clear dependence on this parameter, again especially so for low gas saturations. The results of this study therefore suggest that, for a range of fairly common and realistic conditions, surface-based seismic reflection data are indeed remarkably sensitive to the permeability of gas reservoirs and thus have the potential of providing corresponding first-order constraints.

Time-lapse, multicomponent, surface 3D seismic at Vacuum field mapped and quantified the dynamic changes induced by a CO 2 flood on the porous and fractured dolomites of the San Andres reservoir. Compliance-based effective medium theory simulated the time-lapse variations in seismic velocities in a dual porosity dolomite. Fractures were described as mechanically non-interacting, penny-shaped cracks, and pores were represented as spheres. Numerical modeling and ultrasonic velocity measurements clarified some of the physical mechanisms responsible for time-lapse seismic anomalies in a fractured reservoir. Geomechanical models for stress and saturation changes in a dual porosity rock were derived using those physical mechanisms. Poststack processing of vertical incidence, time-lapse volumes enhanced repeatability of compressional and shear waves. In processing compressional waves, the preferred technique for poststack processing was crossequalization, while a combination of layer stripping and crossequalization was employed on shear waves. Time-lapse, shear waves layer stripping revealed that the rock column at Vacuum field is composed of at least three coarse layers with different principal directions of azimuthal anisotropy. The differences in azimuthal anisotropy were quantified in terms of the orientation of the natural coordinate systems, and fracture density. In the reservoir section, fracture density and orientation changed between the baseline and the repeated seismic survey, thus showing dependency on the CO 2 flood, and in general on the poroelastic changes caused by reservoir engineering operations. The Vacuum field time-lapse experiment shows a subdivision of the reservoir into at least three zones on the basis of saturation and pore pressure changes. The discrimination was made possible by the usage of multicomponent seismology in a fractured reservoir. In particular, real seismic data and numerical modeling with effective medium theory show that time-lapse shear wave splitting can be a powerful indicator of saturation changes in the presence of corrugated fracture sets.

The Journal of the Acoustical Society of America, 2003

We investigate the acoustic and mechanical properties of a reservoir sandstone saturated by two immiscible hydrocarbon fluids, under different saturations and pressure conditions. The modeling of static and dynamic deformation processes in porous rocks saturated by immiscible fluids depends on many parameters such as, for instance, porosity, permeability, pore fluid, fluid saturation, fluid pressures, capillary pressure, and effective stress. We use a formulation based on an extension of Biot's theory, which allows us to compute the coefficients of the stress-strain relations and the equations of motion in terms of the properties of the single phases at the in situ conditions. The dry-rock moduli are obtained from laboratory measurements for variable confining pressures. We obtain the bulk compressibilities, the effective pressure, and the ultrasonic phase velocities and quality factors for different saturations and pore-fluid pressures ranging from normal to abnormally high values. The objective is to relate the seismic and ultrasonic velocity and attenuation to the microstructural properties and pressure conditions of the reservoir. The problem has an application in the field of seismic exploration for predicting pore-fluid pressures and saturation regimes.

SEG Technical Program Expanded Abstracts 2011, 2011

The Middle Devonian Marcellus shale that extends from Ohio and West Virginia, northeast into Maryland, Pennsylvania and New York, is believed to hold in excess of a thousand trillion ft 3 of natural gas. High-quality surface seismic data and top-of-the-line processing are essential to characterize these reservoirs and the overburden formations for safe and cost-effective drilling. A workflow comprising data acquisition and processing to prestack seismic inversion and lithofacies classification for characterizing the shale reservoirs is presented. The key elements in this workflow are dense point-receiver data acquisition and processing in the point-receiver domain. A small data set acquired with a proprietary point-receiver system was available to demonstrate the benefits of this methodology. The data were in an area in New York, where the Marcellus formation is known to exist. In this paper, we present the acquisition, processing and prestack inversion workflow leading to lithofacies classification and reservoir characterization. Prestack inversion provides acoustic and shear impedances, and density that enabled us to calculate the Poisson's ratio and the Young's modulus-the two important elastic attributes for shale-gas reservoir characterization. Based on these results, we find that the Marcellus formation in the study area is elastically highly heterogeneous, as is experienced by drilling and production engineers. We, thus, demonstrate that high-resolution acquisition and processing provides relevant elastic attributes for reservoir characterization to high-grade shale-gas reservoirs in the Marcellus formation of the Appalachian basin.

73rd EAGE Conference and Exhibition incorporating SPE EUROPEC 2011, 2011

Microseismic data sets have been acquired for numerous years in order to determine fracturing distribution and fluid placement in heavy oil reservoirs. Processes such as waterflood, cyclic steaming, steam assisted gravity drainage and hydraulic fracturing have been used to increase permeability and recovery from the reservoir. Primarily, the microseismic event locations and first level source parameters are calculated and analysis of the data is performed in order to gain insight into the fracturing processes that are occurring in the reservoir. As demonstrated by Urbancic et al. (2002), the fracturing processes that occur in the reservoir are complex and can lead to unplanned movement of the injection fluid and/or hydrocarbon. Understanding these processes lead to a better understanding on how to optimize the treatment of the reservoir and in addition can provide some measure of safety during stimulation.