Seismic Vintages Research Articles

Using inverted 4-D seismic and well data to characterise reservoirs from central swamp oil field, Niger Delta

Monitoring of reservoir properties prior to well placements and production is a requirement for optimisation and efficient oil and gas production. This is usually done using well log analyses and 3-D seismic, which are often prone to errors. However, 4-D (Time-lapse) seismic, incorporating numerous 3-D seismic surveys of the same field with the same acquisition parameters, which portrays the transient changes in the reservoir due to production effects overtime, could be utilised because it generates better resolution. There is however dearth of information on the applicability of this approach in the Niger Delta. This study was therefore designed to apply 4-D seismic, well-log and geologic data in monitoring of reservoirs in EK field of the Niger Delta. It aimed at locating bypassed accumulations, and ensuring effective reservoir management. The Field (EK) covers area of about 1200km2 belonging to the early (18ma) Miocene. Data covering two 4-D vintages acquired over fifteen-year interval were obtained from oil companies operating in the field. The data were analysed to determine the seismic structures, horizons, Well-to-Seismic Tie (WST), and wavelets. Well logs and production history data from fifteen selected wells were also collected from the Oil companies. Formation evaluation, petrophysical analysis and inversion alongside geological data were undertaken using Petrel, Shell-nDi, Techlog and Jason Software. Well-to-seismic tie, formation evaluation and saturation monitoring using petrophysical and geological data and software were used to find bypassed hydrocarbon prospects. The seismic vintages were interpreted, and the amounts of change in the reservoir were defined by the differences in Acoustic Impedance (AI) inversions of the base and the monitor seismic. AI rock properties were estimated from all the seismic amplitudes using controlled sparse-spike inversion. The estimated rock properties were used to produce AI maps. The structural analysis showed dominance of NW-SE trending rollover collapsed-crest anticlines in EK with hydrocarbons trapped northwards. There were good ties in wells EK 27, 39. Analysed wavelets revealed consistent amplitude and phase for the WST hence, a good match between the inverted impedance and the well data. Evidence of large pay thickness, ranging from 2875ms (11420 TVDSS-ft) to about 2965ms, were found around EK 39 well with, good yield properties. The comparison between the base of the AI and the current monitor and the generated AI maps revealed zones of untapped hydrocarbons as well as assisted in determining fluids movement. The inverted sections through EK 27, 39 (within 3101 m - 3695 m), indicated depletion in the reservoirs. The extent of the present non-uniform gas-oil contact and oil-water contact movements were from 3554 to 3575 m. The 4-D seismic approach led to better reservoir characterisation, well development and the location of deeper and bypassed hydrocarbon reservoirs.

Active Faulting in Lake Constance (Austria, Germany, Switzerland) Unraveled by Multi-Vintage Reflection Seismic Data

Probabilistic seismic hazard assessments are primarily based on instrumentally recorded and historically documented earthquakes. For the northern part of the European Alpine Arc, slow crustal deformation results in low earthquake recurrence rates and brings up the necessity to extend our perspective beyond the existing earthquake catalog. The overdeepened basin of Lake Constance (Austria, Germany, and Switzerland), located within the North-Alpine Molasse Basin, is investigated as an ideal (neo-) tectonic archive. The lake is surrounded by major tectonic structures and constrained via the North Alpine Front in the South, the Jura fold-and-thrust belt in the West, and the Hegau-Lake Constance Graben System in the North. Several fault zones reach Lake Constance such as the St. Gallen Fault Zone, a reactivated basement-rooted normal fault, active during several phases from the Permo-Carboniferous to the Mesozoic. To extend the catalog of potentially active fault zones, we compiled an extensive 445 km of multi-channel reflection seismic data in 2017, complementing a moderate-size GI-airgun survey from 2016. The two datasets reveal the complete overdeepened Quaternary trough and its sedimentary infill and the upper part of the Miocene Molasse bedrock. They additionally complement existing seismic vintages that investigated the mass-transport deposit chronology and Mesozoic fault structures. The compilation of 2D seismic data allowed investigating the seismic stratigraphy of the Quaternary infill and its underlying bedrock of Lake Constance, shaped by multiple glaciations. The 2D seismic sections revealed 154 fault indications in the Obersee Basin and 39 fault indications in the Untersee Basin. Their interpretative linkage results in 23 and five major fault planes, respectively. One of the major fault planes, traceable to Cenozoic bedrock, is associated with a prominent offset of the lake bottom on the multibeam bathymetric map. Across this area, high-resolution single channel data was acquired and a transect of five short cores was retrieved displaying significant sediment thickness changes across the seismically mapped fault trace with a surface-rupture related turbidite, all indicating repeated activity of a likely seismogenic strike-slip fault with a normal faulting component. We interpret this fault as northward continuation of the St. Gallen Fault Zone, previously described onshore on 3D seismic data.

Hydrocarbon Columns of Oil and Gas Fields in the South Sumatra Basin

The South Sumatra Basin is a prolific basin with a long history of oil and gas exploration that started in early 1900s. It is located in the southern part of Sumatra Island, Indonesia, where more than 300 oil and gas fields have been discovered. The basin contains multiple hydrocarbon reservoir horizons, from Pre-tertiary Basement to Miocene age. The kitchen areas also have various depths, with different levels of maturity. This petroleum system variation is reflected by the field size distribution and the heights of the hydrocarbon columns.Many authors have discussed the petroleum system of this basin and they are useful for providing regional geological perspectives. The oil and gas fields in South Sumatra are usually discussed independently by the operators. Different seismic vintages, density and quality make seismic correlations across the basin challenging. Apart from that, the data restriction is another hurdle in making correlation of the fields. Therefore, statistical studies of the fields and play level understanding become challenging.This study utilizes the Indonesian Petroleum Association Atlas of South Sumatra oil and gas fields, which was published in 1990. Several new fields, especially in fractured basement reservoirs, were added, based on recent publications. Additional information from the IHSE fields database was used to support the study. These data allow a statistical study on hydrocarbon column heights in the South Sumatra Basin. The result of this study could explain more about the charge and seal elements in the basin.

Correlation and Calibration of 4D Seismic Vintages for Effective Postproduction Intervention

Poor or low data quality usually has an adverse effect on the quantitative usage of (4D) seismic data for accurate analysis. Repeatability of 4D Seismic or time-lapse survey is considered as a vital tool for effective, potent, and impressive monitoring of productivity of reservoirs. Inconsistencies and disagreement of ‘time-lapse’ data will greatly affect the accuracy and outcome of research when comparing two or more seismic surveys having low repeatability. Correlation is a statistic procedure that measures the linear relation between all points of two variables. Error due to acquisition and processing must be checked for before interpretation in order to minimize exploration failure and the number of dry holes drilled. The seismic data available for this study comprises of 779 crosslines and 494 inlines. The 4D seismic data consisting of the base Seismic shot in 1998 before production and the monitor Seismic shot in 2010 at different stages of hydrocarbon production were cross correlated to ascertain repeatability between the two vintages. A global average matching process was applied while phase and time shift were estimated using the Russell-Liang technique. Two pass full shaping filters were applied for the phase matching. Maximum and minimum ‘cross-correlation’ are 0.85 (85%) and 0.60 (60%) respectively. Statistics of the ‘cross-correlation’ shift show standard deviation (0.3), variance (0.12), and root mean square (0.78). For high percentage repeatability and maximum correlations, the requested correlation threshold is 0.7 but 1 and 0.99 were obtained for the first and the second matching respectively. Conclusively, the overall results show that there is high repeatability between the 4D seismic data used and the data can be employed conveniently for accurate ‘time-lapse’ (future) production monitoring and investigation on the field.

Assessment of updated low frequency model in delineating bypassed hydrocarbon reservoir: A 4D seismic study of ’X’ - field, offshore, Niger Delta, Nigeria

Aim/objectives: The aim of this research is, to use Time lapse (4D) seismic and investigate the influence of low frequency update in deterministic model-based seismic inversion employed in delineating a prospect saturated with bypassed hydrocarbon accumulation. Method: The dataset employed in this study incorporates 4D seismic volumes with fifteen (15) years production, interval between 2001 baseline and 2016 monitor seismic vintages. The inversion was carried out using full bandwidth of the updated low frequency and bandpass filtered low frequency approaches. The seismic vintages (baseline and monitor) were simultaneously inverted into acoustic impedance volumes for the two approaches. The formation fluid and lithology were discriminated through fluid replacement modelling (FRM) based on the colour separation between brine and gas saturation scenarios. Findings: The two inversion methods employed reveal six (6) zones suspected to be saturated with bypassed hydrocarbons. The delineated bypassed zones are masked in the full bandwidth approach,depicting the effect of the updated low frequency model. Meanwhile, the bandpass filtered approach result presents a better delineated bypassed reservoir as the zones are more pronounced when compared with the full bandwidth approach. Porosity estimate reveals that the bandpass filtered approach is characterized with excellent porosity in the suspected bypassed zones. The results equally gave more reliable and full delineated bypassed zones. Originality and novelty: The dataset employed in this study were obtained from a producing hydrocarbon field which, interest is to maximize the production of oil/gas. The study will bridge the inherent gab observed in using model-based seismic inversion approach to analyse and interpret seismic data in order to delineate hydrocarbon prospects. The research reveals that,the model-based seismic inversion method is still very effective in delineating hydrocarbon prospect when the updated low frequency is bandpass filtered to remove the model effect which influences the inverted acoustic impedance results. Keywords: Porosity; frequency; bypassed; reservoir and impedance

Integrated simulation to seismic and seismic reservoir characterization in a CO2 EOR monitoring application

Understanding the behavior of CO2 injected into a reservoir and delineating its spatial distribution are fundamentally important in enhanced oil recovery (EOR) and CO2 capture and sequestration activities. Interdisciplinary geoscience collaboration and well-defined workflows, from data acquisition to reservoir simulation, are needed to effectively handle the challenges of EOR fields and envisioned future commercial-scale sites for planned and incidental geologic CO2 storage. Success of operations depends on decisions that are based on good understanding of geologic formation heterogeneities and fluid and pressure movements in the reservoir over large areas over time. We present a series of workflow steps that optimize the use of available data to improve and integrate the interpretation of facies, injection, and production effects in an EOR application. First, we construct a simulation-to-seismic model supported by rock physics to model the seismic signal and signal quality needed for 4D monitoring of fluid and pressure changes. Then we use Bayesian techniques to invert the baseline and monitor seismic data sets for facies and impedances. To achieve a balance between prior understanding of the reservoir and the recorded time-lapse seismic data, we invert the seismic data sets by using multiple approaches. We first invert the seismic data sets independently, exploring sensible parameter scenarios. With the resulting realizations, we develop a shared prior model to link the reservoir facies geometry between seismic vintages upon inversion. Then we utilize multirealization analysis methods to quantify the uncertainties of our predictions. Next, we show how data may be more deeply interrogated by using the facies inversion method to invert prestack seismic differences directly for production effects. Finally, we show and discuss the feedback loop for updating the static and dynamic reservoir simulation model to highlight the integration of geophysical and engineering data within a single model.

Time-lapse acoustic impedance variations during CO2 injection in Weyburn oilfield, Canada

For seismic monitoring injected fluids during enhanced oil recovery or geologic [Formula: see text] sequestration, it is useful to measure time-lapse (TL) variations of acoustic impedance (AI). AI gives direct connections to the mechanical and fluid-related properties of the reservoir or [Formula: see text] storage site; however, evaluation of its subtle TL variations is complicated by the low-frequency and scaling uncertainties of this attribute. We have developed three enhancements of TL AI analysis to resolve these issues. First, following waveform calibration (cross-equalization) of the monitor seismic data sets to the baseline one, the reflectivity difference was evaluated from the attributes measured during the calibration. Second, a robust approach to AI inversion was applied to the baseline data set, based on calibration of the records by using the well-log data and spatially variant stacking and interval velocities derived during seismic data processing. This inversion method is straightforward and does not require subjective selections of parameterization and regularization schemes. Unlike joint or statistical inverse approaches, this method does not require prior models and produces accurate fitting of the observed reflectivity. Third, the TL AI difference is obtained directly from the baseline AI and reflectivity difference but without the uncertainty-prone subtraction of AI volumes from different seismic vintages. The above approaches are applied to TL data sets from the Weyburn [Formula: see text] sequestration project in southern Saskatchewan, Canada. High-quality baseline and TL AI-difference volumes are obtained. TL variations within the reservoir zone are observed in the calibration time-shift, reflectivity-difference, and AI-difference images, which are interpreted as being related to the [Formula: see text] injection.

A practical workflow using quantitative interpretation of seismic amplitudes to derisk infill wells in deepwater Gulf of Mexico: The Auger example

Seismic direct hydrocarbon indicators (DHIs) are routinely used in the identification of hydrocarbon reservoirs and in the positioning of drilling targets. Understanding seismic amplitude reliability and character, including amplitude variation with offset (AVO), is key to correct interpretation of the DHI and to enable confident assessment of the commercial viability of the reservoir targets. In many cases, our interpretation is impeded by limited availability of data that are often less than perfect. Here, we present a seismic quantitative interpretation (QI) workflow that made the best out of imperfect data and managed to successfully derisk a multiwell drilling campaign in the Auger and Andros basins in the deepwater Gulf of Mexico. Data challenges included azimuthal illumination effects caused by the presence of the Auger salt dome, sand thickness below tuning, and long-term production effects that are hard to quantify without dedicated time-lapse seismic. In addition, seismic vintages with varying acquisition geometries led to different QI predictions that further complicated the interpretation story. Given these challenges, we implemented an amplitude derisking workflow that combined ray-based illumination assessments and prestack data observations to guide selection of the optimal seismic data set(s) for QI analysis. This was followed by forward modeling to quantify the fluid saturation and sand thickness effects on seismic amplitude. Combined with structural geology analysis of the well targets, this workflow succeeded in significantly reducing the risk of the proposed opportunities. The work also highlighted potential pitfalls in AVO interpretation, including AVO inversion for the characterization of reservoirs near salt, while providing a workflow for prestack amplitude quality control prior to inversion. The workflow is adaptable to specific target conditions and can be executed in a time-efficient manner. It has been applied to multiple infill well opportunities, but for simplicity reasons here, we demonstrate the application on a single well target.

Rock-physics based time-lapse inversion in Delivery4D: synthetic feasibility study for CO2CRC Otway Project

Conventional approach to 4D seismic inversion consists of parallel inversions applied to seismic vintages. Only then, the inverted changes of seismic attributes are converted into petrophysical properties using rock physics. The paper develops a robust approach to 4D seismic inversion based on a Bayesian approach along with rock physics constraints. This means that observed time-lapse seismic response along with the baseline amplitudes are inverted directly into rock properties via pre-defined relations to the seismic properties. To this end, we extend the functional of Delivery - an open-source stochastic inversion software. We illustrate efficiency of Delivery4D using synthetic 4D dataset generated for Stage 2C of CO2CRC Otway project, Victoria. Complexity of the synthetic wavefield resembles field data acquired for the Otway project while all unknown sources of noise/uncertainty are excluded and we have ‘ground-truth’ subsurface properties. Despite the relatively thin CO2 plume, the 4D inversion reduced detected time-lapse anomaly to the location that closely corresponds to the actual CO2 plume. Estimated distributions of the plume characteristics (thickness, saturation and CO2 mass) are overall similar to the static and dynamic geomodels. However, the values inverted at a particular trace may differ significantly. We attribute these discrepancies to the limited seismic resolution and imperfections of the amplitude-preserved seismic processing.

An automated cross‐validation method to assess seismic time‐to‐depth conversion accuracy: a case study on the Cooper and Eromanga basins, Australia

ABSTRACTSelecting a seismic time‐to‐depth conversion method can be a subjective choice that is made by geophysicists, and is particularly difficult if the accuracy of these methods is unknown. This study presents an automated statistical approach for assessing seismic time‐to‐depth conversion accuracy by integrating the cross‐validation method with four commonly used seismic time‐to‐depth conversion methods. To showcase this automated approach, we use a regional dataset from the Cooper and Eromanga basins, Australia, consisting of 13 three‐dimensional (3D) seismic surveys, 73 two‐way‐time surface grids and 729 wells. Approximately 10,000 error values (predicted depth vs. measured well depth) and associated variables were calculated. The average velocity method was the most accurate overall (7.6 m mean error); however, the most accurate method and the expected error changed by several metres depending on the combination and value of the most significant variables. Cluster analysis tested the significance of the associated variables to find that the seismic survey location (potentially related to local geology (i.e. sedimentology, structural geology, cementation, pore pressure, etc.), processing workflow, or seismic vintage), formation (potentially associated with reduced signal‐to‐noise with increasing depth or the changes in lithology), distance to the nearest well control, and the spatial location of the predicted well relative to the existing well data envelope had the largest impact on accuracy. Importantly, the effect of these significant variables on accuracy were found to be more important than choosing between the four methods, highlighting the importance of better understanding seismic time‐to‐depth conversions, which can be achieved by applying this automated cross‐validation method.

Seismic amplitude analysis provides new insights into CO2 plume morphology at the Snøhvit CO2 injection operation

CO2 has been injected at the Snøhvit Field since 2008, with the storage operation split between two distinct injection phases. Until 2011, CO2 was sequestered in the deeper Tubåen Formation before problems with increasing pressure necessitated moving the injection to the overlying Stø Formation.A comprehensive time-lapse seismic monitoring programme has been undertaken over the injection site throughout this period. Uniquely, this study examines four separate seismic vintages starting with the 2003 baseline data and ending with the 2012 repeat survey. The 3D seismic reflection data reveal the seismic character of the anomalies imaged in the Tubåen and Stø Formations to be dissimilar. Time domain analysis and spectral decomposition are used to investigate the CO2 plume morphology in both cases.The seismic response during the initial phase is complex, showing contributions from both fluid and pressure changes. The majority of the reflectivity is ascribed to a build-up of pore-water pressure in the wider reservoir. Seismic analysis of the second phase reveals a simpler distribution, consistent with a conical plume formed by buoyancy-driven upward advection of CO2. The thickness of the spreading layer is calculated, and a maximum temporal thickness of 22 ms is derived from both time and frequency analysis. Direct comparison of the two methodologies reveals good agreement over the central parts of the layer where spectral techniques are applicable. Results are then used to determine the total mass of CO2 in the Stø Formation as 0.51 million tonnes. This is consistent with the true injected mass of 0.55 million tonnes.

Time lapse (4D) and AVO analysis: A case study of Gullfaks field, Northern North Sea

A 4D seismic or time lapse survey has been used to investigate the amplitude versus offset (AVO) effects on seismic data in order to identify anomalies in the Gullfaks field for three different reservoir intervals namely the Tarbert, Cook and Statfjord reservoirs. Repeatability analysis has shown that the earlier seismic vintages are the most unreliable for amplitude anomaly analysis as normalised root-mean square (NRMS) values are greater than 50%. This is above the threshold of good and medium repeatability. Fluid substitution models show increases in both P-wave velocity and density for increasing water saturations with a maximum change of 7.33% in the P-wave velocity, and this is in line with predictions from previous work using the Biot - Gassman equations. AVO modelling for the top Tarbert Formation interface produced scenarios of increasing amplitudes with offset for the presence of hydrocarbons, which dim out with 100% brine saturation. This correlates to class III gas sands for different situations of varying Poisson’s ratio across an interface, which has been previously modelled. Two anomalies were identified with one being related to increasing pressure due to water injection correlating to poor permeability around injector well 34/10-B-33. The second anomaly is a case of potential unswept hydrocarbons that displayed a consistent bright spot throughout all of the seismic vintages (in-inlines and crosslines). AVO attribute analysis of this event produced a class II anomaly. However, when comparing near and far offset seismic data, dimming effect was observed producing contrasting evidence. The dimming offset is viewed to have been as a result of poor repeatability values at far offsets. The modelling of the fluid contents in the studied formations to conform to existing literatures justifies the efficacy of the method.

Effect of hydrocarbon production on reflection amplitude properties of reservoirs—a case study of Kov Field, Niger Delta, Nigeria

A better understanding of how hydrocarbons and other fluids such as brine move in the reservoirs within the Kov Field will enable the improved application of secondary recovery methods such as water and gas injections and also highlight areas within the field that have remaining hydrocarbons. This work focuses on the two major sandstone reservoir intervals, the AG-I and the AG-II all within the Agbada Formation, since they showed prominent amplitude changes. In the AG-I Formation, the results obtained from the production data and rock physics modeling show an increase in the amplitude impedance (AI) contrast around injection wells and a decrease in AI contrast around production wells due to fluid replacement, and it also deals with the pressure changes in correlation to the water injection performed to maintain the reservoir pressure, while in the AG-II Formation, the effect of hydrocarbon production serves to visualize and map the oil-water contact (OWC) as it evolves with the production time; the OWC is not observable on later seismic vintages because the reservoir drops below the OWC. Conclusively, the effect of hydrocarbon production throughout the reservoir and across the entire Field would be beneficial in mapping fluid changes in the Kov Field, which can be utilized for enhanced oil recovery and improved reservoir management.

Quantifying the uncertainty of Gross Rock Volume: a decade of time-to-depth conversion in Sepat Field, Malay Basin

Gross Rock Volume (GRV) range and uncertainty estimation from depth maps is important for resource assessment, and represents a significant contribution from seismic interpretation into the reservoir model. Subsurface uncertainty comes from different factors such as errors in time and depth maps, number of wells drilled, property and facies modelling. This paper focuses on the sensitivity of GRV to various velocity models as the implementation of seismic technologies changed from 2002 to 2013 and as conventional time-to-depth migrated multi-component data was used for depth conversion. GRV estimates from different depth maps are captured and utilized for volumetric and structural uncertainty analysis. Sepat Field was discovered in 1983 and has been interpreted structurally as a 30 km long by 10 km wide, E-W trending, four-way dip closure dissected by normal faults. Like many of the oil and gas fields in the Malay Basin, it is significantly affected by shallow gas clouds especially in the crestal area of the structure (Figure 1). Shallow gas clouds cause amplitude and frequency attenuation and time structure sagging effects which lead to significant uncertainties in structural and stratigraphic mapping of reservoirs below the shallow gas area, and subsequently in the hydrocarbon resource assessment of these fields (Ghazali, 2013). A decade of various seismic vintages and studies are applied to the field in order to achieve better and more accurate depth predictions and quantify uncertainty. As a solution to the shallow gas cloud issue, a 4C seismic survey was acquired in 2012 with the objective of recording both compressional and mode converted shear wave (PS). Acquisition and Processing of PS mode conversions enables improvement in subsurface imaging and subsequent reservoir characterization (Barkved et al., 2004).

4D Joint Stratigraphic Inversion of Prestack Seismic Data: Application to the CO2Storage Reservoir (Utsira Sand Formation) at Sleipner Site

Seismic monitoring is commonly used in the oil industry to follow the evolution of reservoir properties during production. We present a methodology of time-lapse (or 4D) stratigraphic inversion, which is able to provide an estimation of P- and S-wave impedance variations in the reservoir by inverting prestack time-lapse seismic data. The 4D inversion is implemented in the time domain and requires a time scaling law for each repeated seismic dataset in order to adjust the arrival times of homologous events observed in the so-called reference and monitor datasets. This operation is often referred to as the warping problem. The 4D inversion is a 3-step methodology. The first step consists in inverting each seismic vintage independently, thus providing as many P- and S-wave impedance distributions as datasets considered. The second step uses the available P-wave impedance information to solve the warping problem which is crucial to the third and final step: the joint inversion of all available seismic vintages.This 4D inversion sequence was applied to seismic datasets recorded on the Norwegian CO<sub>2<sub/> storage reservoir of Sleipner field located in the North Sea. The latter is becoming a reference industrial site for the long-term storage of carbon dioxide (CO<sub>2<sub/>) in a saline aquifer, the Utsira sand formation. We focused our 4D inversion study on the 1994 and 2006 vintages acquired two years before and ten years after the beginning of CO<sub>2<sub/> injection, respectively. The warping correction resulted in a time-scaling law with a maximum pushdown effect of about 45 ms at the base of the Utsira aquifer. The joint 4D inversion results show more consistency than the single 3D inversion results: the 4D inversion notably provides P-wave impedances for the CO<sub>2<sub/> -saturated sandstones which are close to the values derived from rock physics studies.

Post-stack stratigraphic inversion workflow applied to carbon dioxide storage: application to the saline aquifer of Sleipner field‡

In the Norwegian North Sea, the Sleipner field produces gas with a high CO2 content. For environmental reasons, since 1996, more than 11 Mt of this carbon dioxide (CO2) have been injected in the Utsira Sand saline aquifer located above the hydrocarbon reservoir. A series of seven 3D seismic surveys were recorded to monitor the CO2 plume evolution. With this case study, time-lapse seismics have been shown to be successful in mapping the spread of CO2 over the past decade and to ensure the integrity of the overburden. Stratigraphic inversion of seismic data is currently used in the petroleum industry for quantitative reservoir characterization and enhanced oil recovery. Now it may also be used to evaluate the expansion of a CO2 plume in an underground reservoir. The aim of this study is to estimate the P-wave impedances via a Bayesian model-based stratigraphic inversion. We have focused our study on the 1994 vintage before CO2 injection and the 2006 vintage carried out after a CO2 injection of 8.4 Mt. In spite of some difficulties due to the lack of time-lapse well log data on the interest area, the full application of our inversion workflow allowed us to obtain, for the first time to our knowledge, 3D impedance cubes including the Utsira Sand. These results can be used to better characterize the spreading of CO2 in a reservoir. With the post-stack inversion workflow applied to CO2 storage, we point out the importance of the a priori model and the issue to obtain coherent results between sequential inversions of different seismic vintages. The stacking velocity workflow that yields the migration model and the a priori model, specific to each vintage, can induce a slight inconsistency in the results.

Improved seismic data processing and interpretation for stratistructural petroleum plays in the north of Al-Khafji area, Middle-East

Seismic data with appropriate processing tools, often come to the rescue of interpretation, minimizing the ambiguities involved in analysing complex geological situations. Stratigraphic features associated with structure, play critical role in hydrocarbon entrapment within the Middle-Late Cretaceous reservoirs in the Al-Khafji offshore area. A total of 61 square kilometres high resolution 3D OBC seismic data were acquired in the North Khafji area, with objectives to explore strati-structural traps and their associated reservoir settings. New petroleum plays are intended to be explored after integrating new 3D seismic vintage with older Al-Khafji seismic data interpretation. Present study is aimed at comparing seismic datasets that are processed by different companies. Authors examine and identify the relative merits of data attributes that are suitable for structural and strati-structural traps interpretation. The initial interpretation done during 1997, reports a possible carbonate build-up, correlatable to Gudair formation, which is equivalent to a horizon associated with Aruma-Wasia unconformity. Comparative study made between Khafji and north of Khafji field could not conclusively establish the extension of this carbonate build-up in the North-Khafji area, because of ambiguous nature of structural and stratigraphic anomalies. At places, there is inconsistency among scales of these datasets. However, based on the interpretation of the newly processed seismic data, seismic structure and attributes have been integrated and reinterpreted for scalable anomalies. Present study strongly suggests an exploration potential in the North-Khafji area and stipulates pursuing further geological studies, detailing these seismic anomalies and converting them into commercial petroleum plays in the offshore basin.

Uncertainties in Seismic Facies Analysis for Reservoir Characterisation or Monitoring: Causes and Consequences

Multivariate probabilistic pattern recognition methods such as discriminant analysis are powerful for interpreting seismic data in terms of reservoir properties. They consist of calibrating a mathematical relationship between local seismic information (seismic voxels or pieces of traces extracted at a reservoir level), characterised by a set of measurements, named seismic attributes, and a pre-defined set of classes, named seismic facies. In the context of seismic reservoir characterisation, this methodology provides a map or a volume of most probable facies, which describes the main reservoir heterogeneities. During the last decade, another application of this technique to the interpretation of 4D seismic data has also emerged: in this case, each seismic vintage is interpreted in terms of seismic facies, and differences in the interpretation of one vintage from another are correlated a posteriori to production effects such as fluid substitutions or pressure variations. As a probabilistic method, discriminant analysis allows the evaluation, at least partly, of uncertainty associated with seismic facies interpretation, and assignment probabilities computed by the methodology are a measure of the confidence of the interpretation. However, this uncertainty evaluation is only partial. In this paper, we will describe three other aspects of uncertainties, which are not correctly handled by classical discriminant analysis. The first aspect is linked with measurement errors. To propagate this type of error in seismic facies analysis, we have had to develop a methodology based on a combination of discriminant analysis and interval analysis. The other two aspects of uncertainty are linked with the interpretation of seismic facies. Due to the difference in resolution between seismic data in real reservoir heterogeneities, one seismic facies may correspond to several different fine-scale geological or dynamic scenarios. We will show in this paper how pseudo-well methodology, as well as seismic modelling (in the context of 4D interpretation) can help address this issue.

Seismic preprocessing and amplitude cross‐calibration for a time‐lapse amplitude study on seismic data from the Oseberg reservoir

ABSTRACTThe cross‐calibration of different vintage data is an important prerequisite in attempting to determine the time‐lapse seismic effects induced by hydrocarbon production in a reservoir. This paper reports the preprocessing and cross‐calibration procedures adopted to modify the data of four seismic vintages (1982, 1989, 1992 and 1999) from the Oseberg field in the North Sea, for optimal conditions for a time‐lapse seismic amplitude analysis. The final results, in terms of time‐lapse variations, of acoustic impedance and of amplitude‐versus‐offset, are illustrated for selected data sets. The application of preprocessing to each individual vintage data set reduces the effects of the different acquisition and noise conditions, and leads to consistency in the amplitude response of the four vintages. This consistency facilitates the final amplitude cross‐calibration that is carried out using, as reference, the Cretaceous horizon reflections above the Brent reservoir. Such cross‐calibration can be considered as vintage‐consistent residual amplitude correction.Acoustic impedance sections, intercept and gradient amplitude‐versus‐offset attributes and coherent amplitude‐versus‐offset estimates are computed on the final cross‐calibrated data. The results, shown for three spatially coincident 2D lines selected from the 1982, 1989 and 1999 data sets, clearly indicate gas‐cap expansion resulting from oil production. Such expansion is manifested as a decrease in acoustic impedance and a modification of the amplitude‐versus‐offset trends in the apical part of the reservoir.