Gas-bearing Reservoirs Research Articles

Uncertainty quantification in erosion predictions using data mining methods

The transport of solids in multiphase flows is common practice in energy industries due to the unavoidable extraction of solids from oil and gas bearing reservoirs. The persistent collision of solids to the pipeline can lead to erosion, i.e., the removal of internal surface of the pipeline. Reliable estimates of erosion rates are essential for designing and safely operating pipelines that transport solids. Prediction of erosion rates in multiphase flow is a complex problem due to the lack of accurate models for predicting particle movements in the flow and their impact velocities to the wall. The erosion-rate calculations also depend on the accuracy of the flow regime predictions in the pipeline. The comparisons of existing model predictions to experimental data revealed that the predictions might differ by several orders of magnitude for some operating conditions. The goal of this paper is to introduce a computational framework that estimates the model-prediction uncertainty of erosion-rate models. The inputs are a model predicting erosion rates and a database containing erosion-rate measurements at various operating conditions. The framework utilizes a non-parametric regression analysis, Gaussian Process Modeling (GPM), for estimating the model-prediction uncertainty. We compare two approaches for clustering the data prior to training GPMs: (1) a flow regime based clustering, and (2) a new clustering approach introduced in this paper. The results reveal that the new data clustering approach significantly shrinks the confidence intervals of the uncertainty estimates.

Estimating P- and S-wave inverse quality factors from observed seismic data using an attenuative elastic impedance

P- and S-wave inverse quality factors quantify seismic wave attenuation, which is related to several key reservoir parameters (porosity, saturation, and viscosity). Estimating the inverse quality factors from observed seismic data provides additional and useful information during gas-bearing reservoir prediction. First, we have developed an approximate reflection coefficient and attenuative elastic impedance (QEI) in terms of the inverse quality factors, and then we established an approach to estimate elastic properties (P- and S-wave impedances, and density) and attenuation (P- and S-wave inverse quality factors) from seismic data at different incidence angles and frequencies. The approach is implemented as a two-step inversion: a model-based and damped least-squares inversion for QEI, and a Bayesian Markov chain Monte Carlo inversion for the inverse quality factors. Synthetic data tests confirm that P- and S-wave impedances and inverse quality factors are reasonably estimated in the case of moderate data error or noise. Applying the established approach to a real data set is suggestive of the robustness of the approach, and furthermore that physically meaningful inverse quality factors can be estimated from seismic data acquired over a gas-bearing reservoir.

ПЕРСПЕКТИВЫ ГЕОЛОГИЧЕСКОГО МОДЕЛИРОВАНИЯ НЕФТЕГАЗОНОСНЫХ РЕЗЕРВУАРОВ В ПРОЦЕССЕ БУРЕНИЯ

ПЕРСПЕКТИВЫ ГЕОЛОГИЧЕСКОГО МОДЕЛИРОВАНИЯ НЕФТЕГАЗОНОСНЫХ РЕЗЕРВУАРОВ В ПРОЦЕССЕ БУРЕНИЯ

Formation evaluation challenges in Pliocene gas-bearing reservoirs from the Romanian Western Black Sea shelf

This paper addresses some formation evaluation challenges and petrophysical particularities regarding two gas fields of Early Pliocene age, belonging to the biogenic hydrocarbon system of Western Black Sea Basin - Romanian continental shelf. Although these structures are located at the same depth and only 15 km apart, the wells that intercepted the sands and silts gas-bearing reservoirs indicate an important lateral facies variation and different reservoir qualities. We analyzed and interpreted data from exploration and appraisal wells that targeted these reservoirs, showing that: (1) there is a limited radioactivity contrast between the reservoir and nonreservoir intervals, so a clay volume determination based solely on the gamma ray log is not practical; (2) the reservoirs are characterized by high capillary-bound water contents, leading sometimes to abnormally low resistivity readings; (3) an additional resistivity suppression might be caused by the limited vertical resolution of the electrical logging tools, in the presence of thinly laminated sand - shale intervals; (4) the identification of gas-water contacts based exclusively on pressure gradients may be inaccurate and should be checked against the results of conventional geophysical logs interpretation and of nuclear magnetic resonance logs, for delineating the intervals with bound water or with movable fluids.

Effect of organic type and moisture on CO2/CH4 competitive adsorption in kerogen with implications for CO2 sequestration and enhanced CH4 recovery

Although research attentions for CO2 injection in gas-bearing reservoirs have been drawn to CO2 sequestration with enhanced gas recovery (CS-EGR), the microscopic competitive adsorption mechanism of methane (CH4) and carbon dioxide (CO2) considering the effect of organic type and moisture remains to be determined. In this work, we focus on the competitive adsorption behaviors of CH4 and CO2 on dry and moist realistic kerogen models of different organic types by performing combined molecular dynamics (MD) and grand canonical Monte Carlo (GCMC) simulations. The effects of organic type and moisture content on kerogen pore structures, moisture distribution and interaction between CH4/CO2 and kerogen surfaces are discussed in details. Simulation results show that CO2/CH4 adsorption capacity and adsorption selectivity are in the order of kerogen IA < IIA < IIIA, consistent with the sequence of enterable pore volume fraction (IA, 9.38%; IIA, 13.59%; IIIA, 28.88%). H2O molecules are preferentially adsorbed on the sulfur- and oxygen-containing groups at low moisture, and then migrate and aggregate into clusters in the middle of enterable pores at high moisture. The CO2/CH4 adsorption capacity decreases with increasing moisture content, while the CO2/CH4 adsorption selectivity, specific adsorption energy and CO2 isosteric heat decrease at the beginning, and then increase with the moisture content. Moisture has a bigger effect on the adsorption of CO2 than that of CH4. This study indicates that kerogen IIIA is the optimized organic type for CS-EGS due to its large and stable CO2 storage capacity. Despite its negative effect on gas adsorption capacity, moisture can potentially boost the displacement of CH4 by CO2 at certain moisture conditions. Results of this study lay the foundation for future optimization design of CS-EGR projects with application to coal and shale systems.

Technology Focus: Sand Management and Sand Control (October 2017)

Technology Focus More than half of all existing wells are estimated to require sand control or sand management throughout their lifetime, including unconsolidated sandstone in conventional reservoirs or flowback in unconventional reservoirs. The majority of recent major hydrocarbon discoveries, from Africa (Mozambique, Angola, and Tanzania), transcontinental countries (Egypt), North America (US and Canada), to Far East Asia (Malaysia), are offshore with high-permeability soft formation sands. Approximately half of them are gas-bearing reservoirs. High-flow-rate gas wells are particularly susceptible to sand production. High-velocity or turbulent fluid flow generates large drag forces, dislodging unconsolidated sand particles. The free-flowing particles can erode downhole and surface equipment, including well-control barriers. In a worst-case scenario, this can lead to dangerous uncontrolled production. To ensure successful sand management, a multidisciplinary engagement is necessary. The teams should be able to predict sanding tendencies, detect the sanding locations, select appropriate downhole sand-management and -control devices, and implement the best operating practices for the life of the well. Because of the current downturn, operators are shifting their efforts to the revitalization of existing wells in order to squeeze more production from depleted reservoirs. The same holistic sand-management tactic should be applied to remedial sand control. In summary, production from sand-prone reservoirs is a daunting task, with formidable challenges. Sand management and control remain as an old problem but with new challenges because of the suppressed oil and gas prices. Cost-saving and value-adding solutions are vital now more than ever. For more information, read the featured papers, recommended additional reading, and other publications at OnePetro. Recommended additional reading at OnePetro: www.onepetro.org. SPE 181596 Defining Sand Control in an Uncharted Frontier: A Case Study on the Zawtika Field Development in Myanmar by Graham Grant, PTTEP International, et al. SPE 181360 Case History: Integrated Approach to Sand Management and Completion Evaluation for Sand Producer in a Mature Field, North Sea by M. Ruslan, Dong Oil and Gas, et al. SPE 182511 New Criteria for Slotted-Liner Design for Heavy-Oil Thermal Production by Mahdi Mahmoudi, University of Alberta, et al.

Understanding reservoir heterogeneity through water-saturation prediction via neural network — A case study from offshore Nile Delta

In complex geologic settings with a great degree of heterogeneity in reservoir properties, such as submarine channel complexes as in the Nile Delta province, we face the challenge of characterizing the reservoir based on availability of different seismic attributes. Amplitude variation with offset (AVO) analysis and prestack inversion techniques show impressive results in delineating the gas-bearing reservoirs, especially in clastic systems. However, a shortage of available wells and/or seismic data leads to a challenge in applying AVO and any prestack seismic inversion approaches. In addition, quantitative prediction of water saturation (Sw) from seismic is ambiguous because of its independent nonlinear relationship with conventional seismic attributes and inversion products. Water-saturation prediction away from the well is essential in order to characterize the reservoirs effectively. Therefore, probabilistic neural network (PNN) analysis has been implemented to predict Sw 3D volume using full-stack seismic data and Sw logs. In this case study, we applied the proposed neural network workflow over one of the late-Pliocene gas-sandstone reservoirs, Sequoia Field, in the West Delta Deep Marine (WDDM) concession, offshore Nile Delta, Egypt. The resulting volume then was tested using two blind wells that haven't been used in the analysis. The predicted Sw volume contains fine details that were used with variance and spectral-decomposed volumes to understand the reservoir's internal architecture in terms of sand body geometries and connectivity. The resulting volumes were used to better define the reservoir and optimize a new development well location.

Estimation of Dry Fracture Weakness, Porosity, and Fluid Modulus Using Observable Seismic Reflection Data in a Gas-Bearing Reservoir

Fracture detection and fluid identification are important tasks for a fractured reservoir characterization. Our goal is to demonstrate a direct approach to utilize azimuthal seismic data to estimate fluid bulk modulus, porosity, and dry fracture weaknesses, which decreases the uncertainty of fluid identification. Combining Gassmann’s (Vier. der Natur. Gesellschaft Zurich 96:1–23, 1951) equations and linear-slip model, we first establish new simplified expressions of stiffness parameters for a gas-bearing saturated fractured rock with low porosity and small fracture density, and then we derive a novel PP-wave reflection coefficient in terms of dry background rock properties (P-wave and S-wave moduli, and density), fracture (dry fracture weaknesses), porosity, and fluid (fluid bulk modulus). A Bayesian Markov chain Monte Carlo nonlinear inversion method is proposed to estimate fluid bulk modulus, porosity, and fracture weaknesses directly from azimuthal seismic data. The inversion method yields reasonable estimates in the case of synthetic data containing a moderate noise and stable results on real data.

Diagenesis and its impact on the reservoir quality of Miocene sandstones (Surma Group) from the Bengal Basin, Bangladesh

Rapid supply and deposition of 1000's of meters of Miocene and Pliocene sediment tend to lead to a different set of controls on reservoir quality than older, more slowly buried sandstones. Here we have studied Miocene fluvial-deltaic Bhuban Formation sandstones, from the Surma Group, Bengal Basin, buried to >3,000 m and >110 °C, using a combination of petrographic, geochemical and petrophysical methods in order to understand the controls on Miocene sandstone reservoir quality to facilitate improved prediction of porosity and permeability. The main conclusions of the study are that mechanical compaction processes are the dominant control on porosity-loss although early calcite growth has led to locally-negligible porosity in some sandstones. Mechanical compaction occurred by grain rearrangement, ductile grain compaction and brittle grain fracturing. Calcite cement, occupying up to 41% intergranular volume, was derived from a combination of dissolved and recrystallized bioclasts, an influx of organic-derived carbon dioxide and plagioclase alteration. Clay minerals present include smectite-illite, kaolinite and chlorite. The smectitic clay was probably restricted to low energy depositional environments and it locally diminishes permeability disproportionate to the degree of porosity-loss. Kaolinite is probably the result of feldspar alteration resulting from the influx of organic-derived carbon dioxide. Quartz cement is present in small amounts, despite the relatively high temperature, due to a combination of limited time available in these young sandstones, grain-coating chlorite and low water saturations in these gas-bearing reservoir sandstones. Reservoir quality can now be predicted by considering primary sediment supply and primary depositional environment, the magnitude of the detrital bioclast fraction and the influx of organic-derived carbon dioxide.

Application of Multi-Attribute Crossplots to Tight Gas in X Area, Western China

The gas-bearing reservoir in X area is mainly the tight sandstone reservoir characterized by low porosity and permeability, frequently lateral variation and poor connectivity of single sand. The previous research results reveal that the general seismic attributes analysis cannot meet the requirement of fluid identification. This is because the relationship between seismic attributes and their implication is uncertain and ambiguous, which decreases the precision of both reservoir prediction and fluid identification. To overcome the problem, multi-attribute crossplot technology is proposed from the mathematical statistical point of view rather than the correspondence between the seismic attributes and their geological implication. In this method, the wells which have the same statistical law are classified firstly, and then all the interest wells are retained while the wells beyond the statistical law are eliminated, and the seismic attributes sensitive to the same types of eliminated wells are optimized and used to generate crossplots. The nonzero area of their crossplots results just predicts the potential distribution. The discontinuity of subsurface geological conditions results in the non-continuous shape and the seismic bin lead to the mosaic form. The optimization of sensitive attributes relative to the same types of wells is independent from each other, and thus the order of attributes in crossplots does not affect the final prediction results. This method is based on the statistical theory and suitable for the areas such as the study area abundant of lots of well data. Application to X area proves the effectiveness of this method and predicts plane distribution about different types of gas production. Due to the effect of faults and other geological factors, the partition prediction results using multi-attribute crossplots reach 95% of coincidence which is obviously and far higher than the results of the whole area. The final prediction results show that the potential areas with medium and high gas production are mainly concentrated in the northern part of the study area, where lots of development research will be strengthened.

Elucidating hydraulic fracturing impacts on groundwater quality using a regional geospatial statistical modeling approach

Hydraulic fracturing operations have been viewed as the cause of certain environmental issues including groundwater contamination. The potential for hydraulic fracturing to induce contaminant pathways in groundwater is not well understood since gas wells are completed while isolating the water table and the gas-bearing reservoirs lay thousands of feet below the water table. Recent studies have attributed ground water contamination to poor well construction and leaks in the wellbore annulus due to ruptured wellbore casings. In this paper, a geospatial model of the Barnett Shale region was created using ArcGIS. The model was used for spatial analysis of groundwater quality data in order to determine if regional variations in groundwater quality, as indicated by various groundwater constituent concentrations, may be associated with the presence of hydraulically fractured gas wells in the region. The Barnett Shale reservoir pressure, completions data, and fracture treatment data were evaluated as predictors of groundwater quality change. Results indicated that elevated concentrations of certain groundwater constituents are likely related to natural gas production in the study area and that beryllium, in this formation, could be used as an indicator variable for evaluating fracturing impacts on regional groundwater quality. Results also indicated that gas well density and formation pressures correlate to change in regional water quality whereas proximity to gas wells, by itself, does not. The results also provided indirect evidence supporting the possibility that micro annular fissures serve as a pathway transporting fluids and chemicals from the fractured wellbore to the overlying groundwater aquifers.

Geologic characteristics of hydrocarbon-bearing marine, transitional and lacustrine shales in China

Organic-rich shales spanning in age from Pre-Cambrian to Quaternary were widely deposited in China. This paper elaborates the geology and unique characteristics of emerging and potential hydrocarbon-bearing shales in China. The Pre-Cambrian Sinian Doushantuo to Silurian black marine shales in the intra-shelf low to slope environments were accumulated in South China and Tarim Platform in Northwest China. These marine shales with maturity (Ro) of 1.3–5% are in dry gas window. During Carboniferous to Permian, the shales associated with coal and sandstones were mainly deposited in coastal swamp transitional setting in north China, NE China, NW China and Yangtze platform in South China. These transitional shales are generally clay rich and are potential gas-bearing reservoirs. Since Middle Permian, the lacustrine shales with total carbon content (TOC) up to 30% and Ro mainly in oil window are widely distributed in all the producing basins in China. The lacustrine shales usually have more clay mineral content than marine shales and are characterized by rapid facies change and are interbedded with carbonates and sandstone. The high quality shale reservoir with high TOC, hydrocarbon content and brittle minerals content is usually located at transgressive systems tract (TST) to early highstand systems tract (EHST) interval deposited in anoxic depositional setting. Recent commercial shale gas production from the Silurian Longmaxi marine shale in the southeastern Sichuan Basin, preliminary tight oil production associated with lacustrine hydrocarbon-bearing shale intervals and hydrocarbon shows from many other shales have proven the hydrocarbon-bearing shales in China are emerging and potential shale gas and tight (shale) oil plays. Tectonic movements could have breached the early hydrocarbon accumulation in shales and tectonically stable areas are suggested to be favorable prospects for China shale plays exploration and production.

Solidifying Mud Cake to Improve Cementing Quality of Shale Gas Well: A Case Study

The purpose of this study is to improve the cementing quality of shale gas well by mud cake solidification, as well as to provide the better annular isolation for its hydraulic fracturing development. Based on the self-established experimental method and API RP 10, the effects of mud cake solidifiers on the shear strength at cement-interlayer interface (SSCFI) were evaluated. After curing for 3, 7, 15 and 30 days, SSCFI was remarkably improved by 629.03%, 222.37%, 241.43% and 273.33%, respectively, compared with the original technology. Moreover, the compatibility among the mud cake solidifier, cement slurry, drilling fluid and prepad fluid meets the safety requirements for cementing operation. An application example in a shale gas well (Yuanye HF-1) was also presented. The high quality ratio of cementing quality is 93.49% of the whole well section, while the unqualified ratio of adjacent well (Yuanba 9) is 84.46%. Moreover, the cementing quality of six gas-bearing reservoirs is high. This paper also discussed the mechanism of mud cake solidification. The reactions among H3AlO42- and H3SiO4- from alkali-dissolved reaction, Na+ and H3SiO4- in the mud cake solidifiers, and Ca2+ and OH- from cement slurry form the natrolite and calcium silicate hydrate (C-S-H) with different silicate-calcium ratio. Based on these, SSCFI and cementing quality were improved.

Study on Borehole Wall Real-time Stability of Coal Seam With Coal Cleat When Underbalanced Drilling

Coal seam as the gas productive reservoir and gas-bearing reservoir, it is different from the conventional sandstone reservoir. On the one hand, coal cleat is well-developed in coal seam reservoir. Its characteristics are low porosity, small permeability, large specific surface area, low mechanical strength, strong heterogeneity, low reservoir pressure and so forth. These characteristics determine that drilling has more influence on coal seam reservoir than on conventional sandstone reservoir. In the process of drilling, therefore, in order to reduce or avoid the pollution to coal seam, usually adopt underbalanced drilling way to keep negative differential pressure and to reduce the damage of fluid in borehole flowing into the reservoir. At the same time, when underbalanced drilling, formation fluid flows into the borehole, leading to the formation pressure near the borehole to change. On the other hand, due to coal seam with low mechanical strength, great brittleness, and well-developed coal cleat, in the process of drilling especially underbalanced drilling, borehole wall is prone to collapse. Coal cleat exists in the coal seam and affects its mechanical property. When studying coal seam borehole wall stability, coal cleat must be considered. Considering time effect, the paper established the borehole wall stability model of coal seam with coal cleat when underbalanced drilling, obtained the collapse pressure distribution, and analyzed influence factors of coal seam borehole wall stability, providing theoretical guidance to prevent borehole wall instability. Key words : Coal seam; Underbalanced drilling; Negative differential pressure; Borehole wall stability; Coal cleat

Fracture development on a weak interface ahead of a fluid-driven crack

This paper is aimed at modelling of mechanical interaction of a fluid-driven crack (FDC) with a weak natural interface in a rockmass. FDC may be thought as a magma-filled crack (dyke) typical for volcanic edifices or as a hydraulic fracture artificially induced in oil and gas bearing reservoirs. The main focus of this study is the investigation of the development of delaminating and shear zone on the interface caused by the stresses produced by the FDC that precede the FDC branching and bifurcation when crossing the interface. The mechanism of generation of a network of the connected open-shear cracks is also discussed on the basis of formulation of the problem for the case when the delamination on the interface occurs over a part of the longer shear crack. The method of complex integral equations is used to study two configurations of the fracture pattern developing ahead of the FDC.

Numerical modeling of the influence of heat exchange of reservoir beds with enclosing rocks on gas production from a single well

In the computational experiment, the influence of heat exchange through the top and bottom of the gas-bearing reservoir on the dynamics of temperature and pressure fields in the process of real gas production from a single well is investigated. The experiment is carried out with a modified mathematical model of nonisothermal gas filtration, obtained from the energy and mass conservation laws and the Darcy law. The physical and caloric equations of state together with the Newton-Richman law of heat exchange of a gas reservoir with surrounding enclosing rocks are used as closing relations. It is shown that the influence of the heat exchange with environment on the temperature field of a gas-bearing reservoir is localized in a narrow zone near its top and bottom, although the size of this zone increases with time.

Application of Absorption and Attenuation Analysis Based on Pre-Stack Seismic Data: Su-77 Block Gas Field Example

Most hydrocarbon absorption attenuation studies are based on poststack seismic data processing but, because of multiple stacks at full angle, poststack data will lose some lithology and hydrocarbon-bearing capacity information. To overcome this disadvantage, a prestack angle-domain absorption attenuation analysis technique can be performed for seismic data stacked at various angles to obtain angle-domain-dependent absorption profiles. The absorption anomaly reflects the gas-bearing reservoir and also decreases as the angle increases. Actual data from the Sulige gas field, Ordos Basin, have been processed, and the hydrocarbon predictions match very well with actual drilling results, validating the method's effectiveness.

Understanding the fracture role on hydrocarbon accumulation and distribution using seismic data: A case study on a carbonate reservoir from Iran

Abstract The South Pars, the largest gas field in the world, is located in the Persian Gulf. Structurally, the field is part of the Qatar–South Pars arch which is a regional anticline considered as a basement-cored structure with long lasting passive folding induced by salt withdrawal. The gas-bearing reservoir belongs to Kangan and Dalan formations dominated by carbonate rocks. The fracture role is still unknown in gas accumulation and distribution in this reservoir. In this paper, the Scattering Index (SI) and the semblance methods based on scattered waves and diffraction signal studies, respectively, were used to delineate the fracture locations. To find the relation between fractures and gas distribution, desired facies containing the gas, were defined and predicted using a method based on Bayesian facies estimation. The analysis and combination of these results suggest that preference of fractures and/or fractured zones are negligible (about 1% of the total volume studied in this paper) and, therefore, it is hard to conceive that they play an important role in this reservoir. Moreover, fractures have no considerable role in gas distribution (less than 30%). It can be concluded from this study that sedimentary processes such as digenetic, primary porosities and secondary porosities are responsible for the gas accumulation and distribution in this reservoir.

Liwan Gas Project: South China Sea Deepwater Case Study

This article, written by Senior Technology Editor Dennis Denney, contains highlights of paper IPTC 16722, ’The Liwan Gas Project: A Case Study of a South China Sea Deepwater Drilling Campaign,’ by David Triolo, SPE, and Tracy Mosness, SPE, Husky Energy, and Rana Khalid Habib, Schlumberger, prepared for the 2013 International Petroleum Technology Conference, Beijing, 26-28 March. The paper has not been peer reviewed. The Liwan gas reservoir was discovered in the South China Sea Block 29/26 in September 2006. A sixth-generation, deepwater semisubmersible platform was contracted that subsequently drilled 26 deepwater wells (700- to 1600-m water depth) between November 2008 and November 2011. During the 1,011 days of drilling and testing activity, the rig and onshore supporting teams incurred no lost-time incidents. The rig team drilled 61 593 m of hole below the mudline and ran the associated strings of casing. Nonproductive time consumed 265 days (26.6 %), comprising 65 days waiting on weather, 147 days of rig repair, and 53 days of other unscheduled events. Introduction In April 2006, a dynamically positioned drillship drilled exploration Well Liwan 3-1-1 in 1500 m of water to a depth of 3843 m, discovering the Liwan 3-1 sand-stone, a gas-bearing reservoir. The Liwan 3-1 field is approximately 320 km south-east of Hong Kong in 1300- to 1500-m water depth, as shown in Fig. 1. The nearest field was 64 km northwest. The main reservoir in the Liwan 3-1 gas field (Sand 1) is the Zhujiang formation. Weather and Ocean Environments. The South China Sea presents significant weather conditions that affect offshore operations. Tropical cyclones, typhoons in the western Pacific, occur throughout the year over the northern South China Sea. China’s offshore operators evacuate personnel from permanent and moored offshore facilities when typhoons approach. For dynamically positioned drilling rigs, the typhoon is monitored as it forms and a judgment is made as to when to suspend operations. While drilling, the average time required to suspend operations and recover the lower-marine-riser package (LMRP) or blow-out preventer (BOP) is approximately 72 hours. Nonessential crew are evacuated, and the rig moves out of the path of the typhoon, generally in a southwest direction. There are two monsoons that affect the South China Sea: Northeast (between November and March) and Southwest (between May and September) monsoons, the nomenclature deriving from the predominant wind direction.

Numerical simulation of frequency-dependent seismic response and gas reservoir delineation in turbidites: A case study from China

Abstract To simulate the frequency-dependent response of turbidite reservoirs in the JZ Area, near the Bohai Sea, China, we apply a diffusive and viscous wave equation (DVWE), which takes into account diffusive and viscous attenuation and velocity dispersion in fluid-bearing poroelastic media. We use a seismic data-driven geological model building approach to produce physical parameter sections, which are then used to numerically synthesize the frequency-dependent seismic response in the DVWE-based simulation. The DVWE-based synthetic section shows the characteristic reflection and geometry of turbidites and delineates the phase delay, instantaneous dominant frequency decrease and magnitude attenuation related to the gas-bearing reservoir. The common frequency sections obtained by instantaneous spectral decomposition of the synthetic section show that a low-frequency shadow (LFS) lies immediately beneath the reservoir. Next, following the implications of the numerical simulation, we then apply LFS and fluid mobility to the data volume. Both hydrocarbon indicators clearly delineate the bright gas reservoir and its spatial distribution. The workflow and methodologies can be expected to be applicable to other frequency-dependent hydrocarbon indicators.