A time-lapse seismic repeatability test using the P-Cable high-resolution 3D marine acquisition system

2020 ◽  
Vol 39 (7) ◽  
pp. 480-487
Author(s):  
Patrick Smith ◽  
Brandon Mattox
Keyword(s):  
High Resolution ◽  
Seismic Data ◽  
Low Cost ◽  
Low Frequency ◽  
Time Lapse ◽  
Seismic Signal ◽  
Residual Energy ◽  
Acquisition System ◽  
Positioning Errors ◽  
Seismic Surveying

The P-Cable high-resolution 3D marine acquisition system tows many short, closely separated streamers behind a small source. It can provide 3D seismic data of very high temporal and spatial resolution. Since the system is containerized and has small dimensions, it can be deployed at short notice and relatively low cost, making it attractive for time-lapse seismic reservoir monitoring. During acquisition of a 3D high-resolution survey in the Gulf of Mexico in 2014, a pair of sail lines were repeated to form a time-lapse seismic test. We processed these in 2019 to evaluate their geometric and seismic repeatability. Geometric repetition accuracy was excellent, with source repositioning errors below 10 m and bin-based receiver positioning errors below 6.25 m. Seismic data comparisons showed normalized root-mean-square difference values below 10% between 40 and 150 Hz. Refinements to the acquisition system since 2014 are expected to further improve repeatability of the low-frequency components. Residual energy on 4D difference seismic data was low, and timing stability was good. We conclude that the acquisition system is well suited to time-lapse seismic surveying in areas where the reservoir and time-lapse seismic signal can be adequately imaged by small-source, short-offset, low-fold data.

Hydrocarbon identification using the AVO response correction method based on high-resolution complex spectral decomposition

2020 ◽  
Vol 8 (1) ◽  
pp. SA49-SA61
Author(s):  
Huihuang Tan ◽  
Donghong Zhou ◽  
Shengqiang Zhang ◽  
Zhijun Zhang ◽  
Xinyi Duan ◽  
...  
Keyword(s):  
High Resolution ◽  
Seismic Data ◽  
Spectral Decomposition ◽  
Oil And Gas ◽  
Low Frequency ◽  
Seismic Signal ◽  
Correction Method ◽  
Bohai Bay ◽  
Oil And Gas Exploration ◽  
Response Correction

Amplitude-variation-with-offset (AVO) technique is one of the primary quantitative hydrocarbon discrimination methods with prestack seismic data. However, the prestack seismic data are usually have low data quality, such as nonflat gathers and nonpreserved amplitude due to absorption, attenuation, and/or many other reasons, which usually lead to a wrong AVO response. The Neogene formations in the Huanghekou area of the Bohai Bay Basin are unconsolidated clastics with a high average porosity, and we find that the attenuation on seismic signal is very strong, which causes an inconsistency of AVO responses between seismic gathers and its corresponding synthetics. Our research results indicate that the synthetic AVO response can match the field seismic gathers in the low-frequency end, but not in the high-frequency components. Thus, we have developed an AVO response correction method based on high-resolution complex spectral decomposition and low-frequency constraint. This method can help to achieve a correct high-resolution AVO response. Its application in Bohai oil fields reveals that it is an efficient way to identify hydrocarbons in rocks, which provides an important technique for support in oil and gas exploration and production in this area.

Acquire Ocean Bottom Seismic Data and Time-Lapse Geochemistry Data Simultaneously to Identify Compartmentalization and Map Hydrocarbon Movement

2021 ◽  
Author(s):  
Rick Schrynemeeckers
Keyword(s):  
High Resolution ◽  
Seismic Data ◽  
Time Lapse ◽  
Field Trials ◽  
Detection Methods ◽  
Ocean Bottom ◽  
Field Development ◽  
Dense Grid ◽  
Hydrocarbon Charge ◽  
Sweet Spots

Abstract Current offshore hydrocarbon detection methods employ vessels to collect cores along transects over structures defined by seismic imaging which are then analyzed by standard geochemical methods. Due to the cost of core collection, the sample density over these structures is often insufficient to map hydrocarbon accumulation boundaries. Traditional offshore geochemical methods cannot define reservoir sweet spots (i.e. areas of enhanced porosity, pressure, or net pay thickness) or measure light oil or gas condensate in the C7 – C15 carbon range. Thus, conventional geochemical methods are limited in their ability to help optimize offshore field development production. The capability to attach ultrasensitive geochemical modules to Ocean Bottom Seismic (OBS) nodes provides a new capability to the industry which allows these modules to be deployed in very dense grid patterns that provide extensive coverage both on structure and off structure. Thus, both high resolution seismic data and high-resolution hydrocarbon data can be captured simultaneously. Field trials were performed in offshore Ghana. The trial was not intended to duplicate normal field operations, but rather provide a pilot study to assess the viability of passive hydrocarbon modules to function properly in real world conditions in deep waters at elevated pressures. Water depth for the pilot survey ranged from 1500 – 1700 meters. Positive thermogenic signatures were detected in the Gabon samples. A baseline (i.e. non-thermogenic) signature was also detected. The results indicated the positive signatures were thermogenic and could easily be differentiated from baseline or non-thermogenic signatures. The ability to deploy geochemical modules with OBS nodes for reoccurring surveys in repetitive locations provides the ability to map the movement of hydrocarbons over time as well as discern depletion affects (i.e. time lapse geochemistry). The combined technologies will also be able to: Identify compartmentalization, maximize production and profitability by mapping reservoir sweet spots (i.e. areas of higher porosity, pressure, & hydrocarbon richness), rank prospects, reduce risk by identifying poor prospectivity areas, accurately map hydrocarbon charge in pre-salt sequences, augment seismic data in highly thrusted and faulted areas.

Fluid dynamics at the base of hydrate-bearing sediments at the Vestnesa Ridge inferred from 5 years of high-resolution 4D seismic surveying

2020 ◽  
Author(s):  
Malin Waage ◽  
Stefan Bünz ◽  
Kate Waghorn ◽  
Sunny Singhorha ◽  
Pavel Serov
Keyword(s):  
High Resolution ◽  
Gas Hydrate ◽  
Seismic Data ◽  
Time Lapse ◽  
Stability Zone ◽  
Seismic Surveys ◽  
Free Gas ◽  
4D Seismic ◽  
Hydrate Bearing Sediments ◽  
Hydrate Stability

<p>The transition from gas hydrate to gas-bearing sediments at the base of the hydrate stability zone (BHSZ) is commonly identified on seismic data as a bottom-simulating reflection (BSR). At this boundary, phase transitions driven by thermal effects, pressure alternations, and gas and water flux exist. Sedimentation, erosion, subsidence, uplift, variations in bottom water temperature or heat flow cause changes in marine gas hydrate stability leading to expansion or reduction of gas hydrate accumulations and associated free gas accumulations. Pressure build-up in gas accumulations trapped beneath the hydrate layer may eventually lead to fracturing of hydrate-bearing sediments that enables advection of fluids into the hydrate layer and potentially seabed seepage. Depletion of gas along zones of weakness creates hydraulic gradients in the free gas zone where gas is forced to migrate along the lower hydrate boundary towards these weakness zones. However, due to lack of “real time” data, the magnitude and timescales of processes at the gas hydrate – gas contact zone remains largely unknown. Here we show results of high resolution 4D seismic surveys at a prominent Arctic gas hydrate accumulation – Vestnesa ridge - capturing dynamics of the gas hydrate and free gas accumulations over 5 years. The 4D time-lapse seismic method has the potential to identify and monitor fluid movement in the subsurface over certain time intervals. Although conventional 4D seismic has a long history of application to monitor fluid changes in petroleum reservoirs, high-resolution seismic data (20-300 Hz) as a tool for 4D fluid monitoring of natural geological processes has been recently identified.<br><br>Our 4D data set consists of four high-resolution P-Cable 3D seismic surveys acquired between 2012 and 2017 in the eastern segment of Vestnesa Ridge. Vestnesa Ridge has an active fluid and gas hydrate system in a contourite drift setting near the Knipovich Ridge offshore W-Svalbard. Large gas flares, ~800 m tall rise from seafloor pockmarks (~700 m diameter) at the ridge axis. Beneath the pockmarks, gas chimneys pierce the hydrate stability zone, and a strong, widespread BSR occurs at depth of 160-180 m bsf. 4D seismic datasets reveal changes in subsurface fluid distribution near the BHSZ on Vestnesa Ridge. In particular, the amplitude along the BSR reflection appears to change across surveys. Disappearance of bright reflections suggest that gas-rich fluids have escaped the free gas zone and possibly migrated into the hydrate stability zone and contributed to a gas hydrate accumulation, or alternatively, migrated laterally along the BSR. Appearance of bright reflection might also indicate lateral migration, ongoing microbial or thermogenic gas supply or be related to other phase transitions. We document that faults, chimneys and lithology constrain these anomalies imposing yet another control on vertical and lateral gas migration and accumulation. These time-lapse differences suggest that (1) we can resolve fluid changes on a year-year timescale in this natural seepage system using high-resolution P-Cable data and (2) that fluids accumulate at, migrate to and migrate from the BHSZ over the same time scale.</p>

Design and Implementation of VSP Seismic Data Acquisition System Based on Virtual Instrument Technology

2011 ◽  
Vol 135-136 ◽  
pp. 375-379
Author(s):  
Nai Quan Sun ◽  
Yong Mei Yang ◽  
Rui Jing Dong
Keyword(s):  
Data Acquisition ◽  
Virtual Instrument ◽  
Seismic Data ◽  
Data Acquisition System ◽  
Seismic Signal ◽  
Acquisition System ◽  
Near Surface ◽  
Testing Tool ◽  
Instrument Technology ◽  
Seismic Data Acquisition

Near earth surface can be seen as viscoelastic medium. It’s important to collect VSP seismic signal in near-surface.This paper proposed plan designed for VSP seismic data acquisition system based on virtual instrument technology. This design applied the characteristic that the virtual instrument technology has strong capability in single processing and more abundant, distinct expression to VSP acquisition system. This design makes the acquisition system simple, expand easily. And it provides a practical and useful testing tool to logging exploration of near surface project.

scholarly journals LOW COST SEISMIC DATA ACQUISITION SYSTEM BASED ON OPEN SOURCE HARDWARE AND SOFTWARE TOOLS

2020 ◽  
Author(s):  
Arvid Ramdeane ◽  
Lloyd Lynch
Keyword(s):  
Data Acquisition ◽  
Open Source ◽  
Seismic Data ◽  
Low Cost ◽  
Data Acquisition System ◽  
Software Tools ◽  
Acquisition System ◽  
Seismic Data Acquisition ◽  
Private Network ◽  
Open Source Hardware

The University of the West Indies Seismic Research Centre, Trinidad and Tobago, operates a network of over 50 stations for earthquake and volcanic monitoring in the Eastern Caribbean islands. These stations form a seismic network consisting of various types of instrumentation, and communication systems. Over a period of 11 years, the Centre has embarked on an initiative of upgrading and expanding the current network with combinations of broadband and/or strong motion sensors, high dynamic range digitizers and networking equipment to link each station to centralized observatories via high speed digital data transmission medium. To realize such an upgrade and expansion, the Centre has developed a seismic data acquisition system prototype built using open-source hardware and software tools. The prototype is intended to be low-cost using off the shelf hardware components and open-source seismic related software handling data acquisition and data processing in two separate modules. The prototype uses a three-channel accelerometer sensor and can process data into standard MiniSEED format for easy data archiving and seismic data analysis. A global position module provides network time protocol time synchronization within 1 millisecond for accurate timestamping of data. Data can be stored locally on the prototype in twenty-minute data files or securely transferred to a central location via internet with the use of virtual private network capabilities. The prototype is modular in design allowing for components to be replaced easily and the system software can be updated remotely thus reducing maintenance cost.

Seismic low-frequency shadows and their application to detect CO2 anomalies on time-lapse seismic data: a case study from Sleipner field, North sea

Geophysics ◽  
2021 ◽  
pp. 1-45
Author(s):  
Emmanuel Anthony ◽  
Nimisha Vedanti
Keyword(s):  
North Sea ◽  
Seismic Data ◽  
High Frequency ◽  
Seismic Waves ◽  
Decomposition Analysis ◽  
Low Frequency ◽  
Time Lapse ◽  
Underlying Mechanism ◽  
Real Field ◽  
Saturated Medium

The detection and underlying mechanism of prospect-scale seismic low-frequency shadows (LFS) has been an issue of debate. Even though the concept of LFS is widely accepted, the practical applicability of the method remains limited due to few real field case studies and little understanding of the underlying attenuation mechanism. To characterize the attenuation phenomenon responsible for the occurrence of LFS in CO2 saturated formations, we use the diffusivity and viscosity of the fluid saturated medium to derive a complex velocity function that characterizes a high-frequency attenuation phenomenon responsible for the occurrence of LFS in a CO2 saturated formation. Synthetic seismic data sets representing pre- and post- CO2 injection scenarios were generated using 2D diffusive viscous equations to model the LFS and understand its occurrence mechanism. Furthermore, to demonstrate the applicability of LFS in a real field, a spectral decomposition analysis of time-lapse 3D seismic data of the Sleipner field, North Sea, was carried out using the continuous wavelet transform. LFSs were clearly detected below the reservoir base at frequencies lower than 30 Hz in the post- CO2 injection surveys. It is shown that the seismic low-frequency shadows are not artefacts but occur due to attenuation of the high frequency components of the propagating seismic waves in the CO2 saturated Utsira Formation. The attenuation of these frequencies is a result of the diffusivity and viscosity of the fluid saturated medium. The low-frequency shadows are localized anomalies at the base of the formation; hence with the present approach, these anomalies cannot be related to the migration of the CO2 plume in the Utsira Formation.

High-resolution acoustic impedance inversion to characterize turbidites at Marlim Field, Campos Basin, Brazil

2014 ◽  
Vol 2 (3) ◽  
pp. T143-T153 ◽  
Author(s):  
Tatiane M. Nascimento ◽  
Paulo T. L. Menezes ◽  
Igor L. Braga
Keyword(s):  
High Resolution ◽  
Seismic Data ◽  
Acoustic Impedance ◽  
Structural Information ◽  
Low Frequency ◽  
Seismic Inversion ◽  
Background Model ◽  
Rock Properties ◽  
High Porosity ◽  
Campos Basin

Seismic inversion is routinely used to determine rock properties, such as acoustic impedance and porosity, from seismic data. Nonuniqueness of the solutions is a major issue. A good strategy to reduce this inherent ambiguity of the inversion procedure is to introduce stratigraphic and structural information a priori to better construct the low-frequency background model. This is particularly relevant when studying heterogeneous deepwater turbidite reservoirs that form prolific, but complex, hydrocarbon plays in the Brazilian offshore basins. We evaluated a high-resolution inversion workflow applied to 3D seismic data at Marlim Field, Campos Basin, to recover acoustic impedance and porosity of the turbidites reservoirs. The Marlim sandstones consist of an Oligocene/Miocene deepwater turbidite system forming a series of amalgamated bodies. The main advantage of our workflow is to incorporate the interpreter’s knowledge about the local stratigraphy to construct an enhanced background model, and then extract a higher resolution image from the seismic data. High-porosity zones were associated to the reservoirs facies; meanwhile, the nonreservoir facies were identified as low-porosity zones.

Streamline-based integration of time-lapse seismic and production data into petroleum reservoir models

Geophysics ◽  
2012 ◽  
Vol 77 (6) ◽  
pp. M73-M87 ◽  
Author(s):  
Alvaro Rey ◽  
Eric Bhark ◽  
Kai Gao ◽  
Akhil Datta-Gupta ◽  
Richard Gibson
Keyword(s):  
High Resolution ◽  
Finite Difference ◽  
Seismic Data ◽  
Time Lapse ◽  
Seismic Inversion ◽  
Absolute Permeability ◽  
Production Data ◽  
Petroleum Reservoir ◽  
Seismic Surveys ◽  
Fluid Saturation

We have developed an efficient approach of petroleum reservoir model calibration that integrates 4D seismic surveys together with well-production data. The approach is particularly well-suited for the calibration of high-resolution reservoir properties (permeability) because the field-scale seismic data are areally dense, whereas the production data are effectively averaged over interwell spacing. The joint calibration procedure is performed using streamline-based sensitivities derived from finite-difference flow simulation. The inverted seismic data (i.e., changes in elastic impedance or fluid saturations) are distributed as a 3D high-resolution grid cell property. The sensitivities of the seismic and production surveillance data to perturbations in absolute permeability at individual grid cells are efficiently computed via semianalytical streamline techniques. We generalize previous formulations of streamline-based seismic inversion to incorporate realistic field situations such as changing boundary conditions due to infill drilling, pattern conversion, etc. A commercial finite-difference flow simulator is used for reservoir simulation and to generate the time-dependent velocity fields through which streamlines are traced and the sensitivity coefficients are computed. The commercial simulator allows us to incorporate detailed physical processes including compressibility and nonconvective forces, e.g., capillary pressure effects, while the streamline trajectories provide a rapid evaluation of the sensitivities. The efficacy of our proposed approach was tested with synthetic and field applications. The synthetic example was the Society of Petroleum Engineers benchmark Brugge field case. The field example involves waterflooding of a North Sea reservoir with multiple seismic surveys. In both cases, the advantages of incorporating the time-lapse variations were clearly demonstrated through improved estimation of the permeability heterogeneity, fluid saturation evolution, and swept and drained volumes. The value of the seismic data integration was in particular proven through the identification of the continuity in reservoir sands and barriers, and by the preservation of geologic realism in the calibrated model.

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