Reservoir Fluid Content Research Articles

Using time-lapse seismic velocity changes to monitor the Domo de San Pedro Geothermal field, Mexico

The Domo de San Pedro Geothermal field, located in the westernmost part of the trans-Mexican volcanic belt, is part of a silicic volcanic complex. Geothermal energy is produced since 2015 from 9 wells as deep as 3 km. We monitor geothermal operations using a continuous seismic dataset from a temporary network of 20 broadband stations from March 2021 to January 2022. The well logs describing the geothermal operations allow us to investigate the seismic response of the geothermal field to fluid extraction and re-injection across the geothermal wells. We produced a catalog of 217 local earthquakes and derive an optimized 1D velocity model for the geothermal field between 1.2 m above the sea level (masl) and 12 km depth. Apparent velocity changes (dv/v) are measured using seismic ambient noise interferometry from the coda of noise cross-correlations. Next, we identify and locate subsurface velocity anomalies, combining the methods of station collapse sensitivity and ambient noise imaging applied to the continuous seismic noise records. We distinguish three periods of seismic activity where prominent changes in velocity coincide with the re-injection of fluids and significant variation in the production rate of the geothermal wells. We determine the distribution of these velocity transients inside the geothermal field and propose that they are associated with variations in reservoir fluid content and effective stress changes beneath the volcanic system and are responsible for induced microseismicity. Our study shows that implementing dv/v quantification as an additional tool for geothermal seismic monitoring can lead to an improved understanding of the behavior of the geothermal system over time and ultimately de-risk geothermal operations.

Hydrocarbon Mapping on Reservoir Carbonate Using AVO Inversion Method

Amplitude Versus Offset (AVO) inversion has been applied for reservoir analysis focused on the horizon carbonate Peutu and Belumai. Simultaneous inversion analysis is used to determine gas anomaly inside carbonate-rocks and it’s spread laterally around target zones. It is based on the fact that small Vpand Vs value changes are going to show the better anomaly to identify reservoir fluid content. The AVO inversion method applies angle gather data as the input and then it is inverted to produce P impedance (Zp) and S impedance (Zs). Zp and Zs are derived to produce Lambda-Rho and Mu-Rho that are sensitive to fluid and lithology. Value of Mu-Rho between 44–65 Gpa gr/cc while value of Lambda-Rho smaller than 10 Gpa gr/cc (for carbonate-rock filled by fluid). This research found that Lambda-Rho is the best parameter to show the existence of hydrocarbon in the case of gas. While Mu-Rho is the best parameter to show the differences in lithology.

Spectral Decomposition AVO attributes for identifying potential hydrocarbon-related frequency anomalies

Low-frequency seismic anomalies have long been a subject of interest to geoscientists involved in hydrocarbon exploration since such ‘gas-shadows’ can be a direct hydrocarbon indicator (DHI). Published studies have demonstrated evidence for them potentially resulting from increased seismic attenuation and velocity dispersion, as a result of hydrocarbon saturation. The topic gained wide interest during the 2000s with well-cited publications by Castagna et al. (2003), Ebrom (2004), Chapman et al. (2005, 2006) and Odebeatu et al. (2006), to name a few. The consensus of these studies was that hydrocarbon related frequency effects are predicted to be detectable on stacked seismic data. Furthermore, it has been suggested that low frequencies tend to show the highest sensitivity to fluid changes. (e.g. Korneev et al., 2004). The effect has been shown not only from seismic data; studies involving laboratory tests and borehole data provide similar conclusions. Overall there is general agreement that the effect exists. However the physical cause remains inconclusive. Several studies have also shown evidence that hydrocarbon reservoirs have an amplitude-versus-offset (AVO) frequency dependence (e.g. Chapman et al. (2005, 2006), Odebeatu et al. (2006), Liu et al. (2006), Ren et al. (2007), Zhang et al. (2007), Chen et al. (2008), Wu et al. (2014)). In the modelled case of gas-saturated sands, low frequencies have tended to show the greatest change in amplitude with offset (Figure 1a). The idea of using AVO and Spectral Decomposition (SD) to understand frequency anomalies and potential links to reservoir fluid content has been approached by several of these authors. The published work largely used model-based techniques to predict AVO effects for different frequencies (Figure 1b), and then applied this information to aid interpretation of anomalies observed on iso-frequencies sections. The results convincingly suggest that there are differences in the spectral content of seismic data which could be exploited for improved hydrocarbon identification. The results of these pioneering publications is the basis from which the workflow presented in this paper was conceived. Here these ideas are approached from an interpretation perspective and applied in a practical manner using commercial interpretation software.

Integration of 4D Seismic in Steam-Assisted-Gravity-Drainage Reservoir Characterization

Summary 4D seismic is one of the main sources of dynamic data for heavy-oil-reservoir monitoring and management. 4D seismic is significant because seismic attributes such as velocity and impedance depend on variations in reservoir-fluid content, temperature, and pressure distribution as a result of hydrocarbon production. Thus, the large-scale nature of fluid flow within the reservoir can be evaluated through information provided by 4D-seismic data. Such information may be described as anomalies in fluid flow that can be inferred from the unusual patterns in variations of a seismic attribute. During steam-assisted gravity drainage (SAGD), the steam-chamber propagation is fairly clear from 4D-seismic data mainly because of changes in reservoir conditions caused by steam injection and bitumen production. Anomalies in the propagation of the steam chamber reflect the quality of fluid flow within the reservoir. A practical methodology is implemented for integration of 4D seismic into SAGD reservoir characterization for the Surmont project.

Play fairway analysis of geothermal resources across the state of Hawaii: 2. Resource probability mapping

We develop a new geostatistical method to combine evidence provided by diverse geological data sets and produce maps of geothermal resource probability. The application is to the State of Hawaii, and the data sets include the locations and ages of mapped volcanic centers, gravity and magnetotelluric measurements, groundwater temperature and geochemistry, ground surface deformation, seismicity, water table elevation, and groundwater recharge. Using the basic principles of Bayesian statistics, these data and expert knowledge about the effects and importance of the data are used to compute the probabilities of the primary resource qualities of elevated subsurface heat, reservoir permeability, and reservoir fluid content. The product of these marginal probabilities estimates the joint probability of all three qualities and hence the probability of a successful geothermal prospect at each map point. An analogous set of algorithms is used to quantify the confidence in the probability at each point. Not surprisingly, we find that successful geothermal prospects are most probable on the active volcanoes of Hawaii Island, including the area of Hawaii’s single geothermal energy plant. Probability decreases primarily with shield volcano age, being relatively moderate in select locations on Maui and Lanai, relatively low on Oahu, and minimal on Kauai. Future exploration efforts should consider these results as well as the practical, societal, and economic conditions that influence development viability. The difficulties of interisland power transmission mean that even areas with moderate to low probabilities are worth investigating on islands with population centers.

Improving the accuracy of determining the character saturation reservoirs on the results of log interpretation in the oil field ”K”(Tomsk region)

Log interpretation has revealed a number of factors that have a significant impact on the determination of reservoir fluid content (oil saturation factor). The presented research paper is focused on the analysis of petrophysical properties of reservoir fluids considering laboratory studies of core samples. Based on core sample analysis, data of laboratory studies have been correlated to estimates of radioactive logging and high-frequency induction logging. To determine the oil saturation factor a method which considers the effect of mixed clay on reservoir fluid saturation has been proposed.

Model-based Assessment of Seismic Monitoring of CO2 in a CCS Project in Alberta, Canada, Including a Poroelastic Approach

The theoretical detectability of CO2 is investigated for the Quest Carbon Capture and Storage (CCS) project in Alberta, Canada. This is completed by using Gassmann fluid substitution and elastic seismic modeling. The study indicates that for the period of one year injection, the location and spatial distribution of the CO2 plume could be detected in the seismic data. This is providing the data have good bandwidth and a high signal to noise ratio. However, pore fluid properties such as density, velocity, viscosity, and saturation are neglected in elastic modeling in spite of the reservoir rocks being porous media saturated with fluids. Another phase of the study includes developing a more accurate forward modeling algorithm that takes the fluid properties into account. For this purpose, the Biot's equations of motion in poroelastic media are employed to develop a finite difference algorithm to simulate the wave propagation in poroelastic media. To examine the algorithm, a numerical example is defined based on the Quest project. The results reveal that the algorithm properly handles the layered models and thus can be used in the future to examine more complex models. This approach may also be better than elastic modeling for theoretical monitoring of CO2 since the reservoir fluid content is considered in the modeling process.

Optimal trace selection for AVA processing of shale-sand reservoirs

When processing data, a principal aim is to maximize information inferred from a data set by minimizing the expected postprocessing uncertainties on parameters of interest. Nonlinear statistical experimental design (SED) methods can be used to find optimal trace profiles for processing amplitude-variation-with-angle (AVA) surveys that account for all prior petrophysical information about the target reservoir. Optimal selections change as prior knowledge of rock parameters and reservoir fluid content changes, and which of the prior parameters have the greatest effect on selected traces can be assessed. The results show that optimal profiles are far more sensitive to prior information about reservoir porosity than to information about saturating fluid properties. By applying ray-tracing methods, AVA results can be used to design optimal processing profiles from seismic data sets for multiple targets, each with different prior-model uncertainties.

Comparison of Borehole Velocity-Prediction Models and Estimation of Fluid Saturation Effects: From Rock Physics to Exploration Problem

Abstract We analyzed three types of elastic-wave velocity-prediction models by means of well-log synthetics and seismic-section ties by considering fluid saturation in five wells, including clastic and carbonate reservoirs. The elastic moduli of a formation are functions of the elastic moduli of the solid matrix and the fluid components, as well as the pore geometry. By using the volumes of different minerals and fluids obtained from log analysis, we calculated the elastic moduli of the matrix and fluid. Changes in velocities between invaded and uninvaded zones are quite signifi cant and often ignored in well-to-seismic ties. We applied three different models (time-average, Gassmann, and Kuster-Toks?z), seeking a best velocity-prediction model. The time-average equation is not recommended for velocity prediction and is especially inaccurate for gas-reservoir intervals. The Gassmann equation is usually the most appropriate for low-frequency seismic data. The Kuster-Toks?z model is best for high-frequency data. Also, because it takes pore geometry intoccount, it should be considered when the pore shape is signifi - cant in determining formation velocity (pore aspect ratio < 0.3). There can be a trade-off between low-frequency dispersion effects, favouring the Gassmann application, and pore geometry effects, favouring the Kuster-Toks?z application. Our exploration case study indicates that the high-frequency (Kuster-Toks?z) model may usually be a better choice. This case study yields good agreement between the predicted pore aspect ratio (0.12) and that from a laboratory measurement (0.166) in the study area. Comprehensive research encompassing borehole-velocity prediction models, laboratory study of core such as pore geometry statistics, well-log analysis, and study of seismic response is required. Introduction A question of considerable interest in seismic lithology studies is how best to predict elastic-wave velocities, both compressional (or P, sonic, or acoustic) and shear (or S), for composite media (e.g., porous rocks) in cases where there are no velocity logs available. Nuclear logs have sometimes been used to derive sonic and shear logs(1) but, unfortunately, estimation of velocities by thisalgorithm is quite inaccurate. For one thing, it does not take intoccount fluid saturation. For wells in western Canada, sonic logs re commonly available but shear logs are rarely available. And S wave logs are often required in seismic lithology studies that seek to understand the effects of reservoir fluid content, such as in AVO studies. The purpose of this paper is twofold. First, by comparing different velocity-prediction models for composite media, it tries to find a best model to predict P-wave and S-wave velocities, VP and VS. Second, by considering fluid-saturation effects, it applies predictions to exploration problems by tying into field seismic data with synthetic seismograms that incorporate velocities predicted from different porous-rock models. Laboratory studies show that there are significant changes in elastic-wave velocities in a porous rock depending on whether it is dry, gas-saturated, water-saturated, or oil-saturated(2-6). Figureshows P- and S-wave velocity comparisons between laboratory measurements and predictions from rock-physics models(7, 8).

3-D Seismic Benefits From Exploration Through Development: An Exxon Perspective

Exxon has participated in over 370 three-dimensional (3-D) seismic surveys in 13 countries since the late-1970s. The world-wide distribution of our experience is led by western Europe, the Gulf of Mexico, and Canada. These surveys have added significant value to our upstream operations and we consider 3-D seismic to be the single most important technology to ensure the effective and cost-efficient exploration and development of our oil and gas fields. Exxon is applying 3-D seismic technology in established exploration trends, the early phases of field delineation, development decision making, and exploitation. Our use of 3-D seismic surveys has led to the addition of new reserves, drilling of fewer dry or marginal exploration wells, and optimization of the number and placement of delineation, development, and secondary recovery wells. These benefits are a result of superior structural definition, more detailed reservoir descriptions, reservoir fluid content characterizations, and quantitative interpretation methods. Although 3-D seismic surveys are expensive, when balanced against potential investments in nonproductive acreage, a costly dry hole or two, a misplaced platform, incorrect assumptions on reservoir extent and geometry, or perhaps premature field abandonment, 3-D seismic surveys in most areas are money well spent.

Determination of Reservoir Fluid Content by Seismic Modeling: ABSTRACT

Determination of Reservoir Fluid Content by Seismic Modeling: ABSTRACT

Formation Evaluation by Analysis of Hydrocarbon Ratios

The ratio of methane to the heavier hydrocarbon components ethane, propane, butane, and pentane is indicative of gas, oil and water propane, butane, and pentane is indicative of gas, oil and water productive potential. The Steam Still-Reflux Unit, used in conjunction productive potential. The Steam Still-Reflux Unit, used in conjunction with mud logs and gas chromatographs yields a quantitative analysis from which this ratio can be plotted. Introduction Mud logging was first offered commercially in Aug., 1939. This logging method quickly gained favor among many operators because the type of fluid in the formation could be determined within minutes after the formation was drilled. The presence and magnitude of the methane show was and is the most important factor in mud log interpretation. However this magnitude in some instances was improperly understood, and as a consequence some operators still do not use mud logging, even though the early technique frequently made the difference between a successful well and an abandoned hole. Both the "hot wire" log of gas combustibles in the sample and the percent-of-gas log obtained with the conventional gas percent-of-gas log obtained with the conventional gas trap and the gas chromatograph indicate only that the reservoir in question contains hydrocarbons. These methods do not necessarily indicate the quantitative amounts of the various hydrocarbons in the mud. The addition of a new Steam Still-Reflux gas sampling system to gas chromatography enables accurate determination of the composition of the mud gas sample. A knowledge of gas composition makes it possible to establish the relationship of methane to possible to establish the relationship of methane to the heavier hydrocarbon shows. An awareness of this relationship led to a new, additional mud log interapretative technique that permits relating the quantitative amounts of methane (C1), ethane (C2), propone (C3), butane (C4), and pentane (C5) in-place propone (C3), butane (C4), and pentane (C5) in-place reservoir fluid content. A long-accepted premise is that as formations are drilled, the drilling mud filtrate partially flushes the formation fluid ahead of the bit. It was generally thought that the formations were flushed to an irreducible minimum generally considered to be about 30 percent of in-place fluid. Experience in mud logging, however, has shown that this rarely happens. This partial flushing does not prevent mud logging from successfully determining productive or nonproductive formations. Experienced logging engineers, in possession of quantitative gas analyses, make interpretations that take into account the flushing that results in rocks of various permeabilities, the effect of overbalanced mud weight and the effect of initial filtrate loss. Method Ordinarily, when formation cuttings are drilled they retain much of the formation pore fluid. This fluid is released to the mud column as the cuttings travel up the annulus. Most of the formation fluid in the cuttings will be "produced" into the drilling mud during the top 500 ft of hole travel. Conventionally, a mud sample is diverted to a mechanically operated gas trap to obtain a sample of the gas in the mud. The efficiency of this trap is from 15 to 70 percent, depending upon the gel strength of the mud, the amount of mud flowing through the trap and the rotation speed of the trap impeller. JPT P. 665

Estimation of Interstitial Water From the Electric Log

Abstract A comparison is made between the amount of interstitial water found by analysisin cores and that estimated from the resistivity curve of the electric log forthe corresponding strata of producing reservoirs. It is shown that while thedetermined and the estimated water saturations are in good agreement in somecases, this agreement may be due to a fortuitous compensation of errors.Estimates of water saturations made from the electric log by use of existingrelations should, therefore, be employed with caution. Also presented are dataon the variation of salinity of interstitial waters in reservoir sands, and onthe effect of variation of salinity and porosity on the validity of estimatesof water content made from the electric log. Introduction Throughout the history of electric logging there have been recurrent cyclesof optimism and pessimism as to the value of the electric log in thequantitative estimation of reservoir fluid content. The very early days ofelectric logging were an optimistic period, in which there was widespread faithin the ability of the resistivity curve to reflect fluid content, and in theability of the potential curve to indicate textural characteristics. In timethe accumulation of exceptions to this idealistic behavior brought about ageneral disillusionment, and caused the more pessimistic of those dealing withelectric logs to believe that the sole importance of the log lay instratigraphic correlation. Within the last several years optimism as to the quantitative use of theelectric log has been revived, primarily as the result of the stimulating workof G. E. Archie on the estimation of interstitial water in sands fromresistivity data. Even though the general trend of thought on the quantitativevalue of the electric log reflects optimism, it is inevitable that there aresome widely divergent opinions of the validity of quantitative estimates basedon the electric log. T.P. 2936