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.

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.

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>

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.

Using 3D finite-difference modeling to design wide-azimuth surveys for improved subsalt imaging

Geophysics ◽  
2007 ◽  
Vol 72 (5) ◽  
pp. SM231-SM239 ◽  
Author(s):  
Carl J. Regone
Keyword(s):  
Image Quality ◽  
Finite Difference ◽  
Three Dimensional ◽  
Design Parameters ◽  
Ocean Bottom ◽  
Field Development ◽  
Wide Range ◽  
Dense Grid ◽  
Subsalt Imaging ◽  
Important Design

Three-dimensional finite-difference modeling studies conducted over subsalt structures in the deepwater Gulf of Mexico confirm the deficiencies of narrow-azimuth towed-streamer surveys and predict significant improvement in image quality with wide-azimuth methods. Finite-difference modeling has provided important design parameters for two separate approaches for wide-azimuth surveys: ocean-bottom receivers distributed in a sparse grid on the ocean floor coupled with a dense grid of source points on the surface, and a wide-azimuth towed-streamer method using multiple seismic vessels in a novel configuration. These two methods complement each other. Ocean-bottom receivers may be used effectively where field development has resulted in many obstacles that might interfere with towed-streamer methods, where the required size of the 3D survey is not too extensive, or where very long offsets are required for all azimuths. Towed-streamer methods are more efficient for large surveys, and key parameters in the wide-azimuth towed-streamer method can be varied to provide a wide range of cost versus data-quality options to make the method suitable for application in scenarios ranging from exploration to field development.

scholarly journals Repeatability of high-resolution 3D seismic data

Geophysics ◽  
2019 ◽  
Vol 84 (1) ◽  
pp. B75-B94 ◽  
Author(s):  
Malin Waage ◽  
Stefan Bünz ◽  
Martin Landrø ◽  
Andreia Plaza-Faverola ◽  
Kate A. Waghorn
Keyword(s):  
Fluid Flow ◽  
High Resolution ◽  
Seismic Data ◽  
Seismic Energy ◽  
Time Lapse ◽  
The Arctic ◽  
3D Seismic ◽  
Factors Affecting ◽  
Gas Chimneys ◽  
3D Seismic Data

High-resolution 4D (HR4D) seismic data have the potential for improving the current state-of-the-art in detecting shallow ([Formula: see text] below seafloor) subsurface changes on a very fine scale (approximately 3–6 m). Time-lapse seismic investigations commonly use conventional broadband seismic data, considered low to moderate resolution in our context. We have developed the first comprehensive time -lapse analysis of high-resolution seismic data by assessing the repeatability of P-cable 3D seismic data (approximately 30–350 Hz) with short offsets and a high density of receivers. P-cable 3D seismic data sets have for decades been used to investigate shallow fluid flow and gas-hydrate systems. We analyze P-cable high-resolution 4D (HR4D) seismic data from three different geologic settings in the Arctic Circle. The first two are test sites with no evidence of shallow subsurface fluid flow, and the third is an active seepage site. Using these sites, we evaluate the reliability of the P-cable 3D seismic technology as a time-lapse tool and establish a 4D acquisition and processing workflow. Weather, waves, tide, and acquisition-parameters such as residual shot noise are factors affecting seismic repeatability. We achieve reasonable quantitative repeatability measures in stratified marine sediments at two test locations. However, repeatability is limited in areas that have poor penetration of seismic energy through the seafloor, such as glacial moraines or rough surface topography. The 4D anomalies in the active seepage site are spatially restricted to areas of focused fluid flow and might likely indicate changes in fluid flow. This approach can thus be applied to detect migration of fluids in active leakage structures, such as gas chimneys.

The influence of volcanic rocks on the characterization of Rosebank Field – new insights from ocean-bottom seismic data and geological analogues integrated through interpretation and modelling

2016 ◽  
Vol 8 (1) ◽  
pp. 373-384 ◽  
Author(s):  
S. Poppitt ◽  
L. J. Duncan ◽  
B. Preu ◽  
F. Fazzari ◽  
J. Archer
Keyword(s):  
Seismic Data ◽  
Reservoir Characterization ◽  
Seismic Analysis ◽  
Volcanic Rocks ◽  
Flood Basalt ◽  
Ocean Bottom ◽  
Volcanic System ◽  
Field Development ◽  
Velocity Models ◽  
Depth Prediction

AbstractDuring Late Paleocene–Early Eocene times, the modern Rosebank structure was located at the juxtaposition of the easterly advancing Flett volcanic system and the northerly prograding Flett delta. As a result, the Rosebank reservoir sandstones are interstratified with volcanic and volcaniclastic rocks, offering challenges for reservoir imaging, depth prediction and reservoir characterization. These challenges have driven the application of Ocean Bottom Node (OBN) seismic technology. OBN data have yielded improved velocity models for depth conversion, better reservoir definition and key insights to aid the modelling of sand distribution from seismic attributes. Spectral decomposition of the OBN seismic data has facilitated the extraction of distinct volcanic subunits, whilst spectral enhancement has enabled visualization of complex stacking patterns within individual igneous layers. To complement the seismic analysis, detailed geological analogue studies have been undertaken in volcanic provinces such as the Palaeogene volcanic district of SE Greenland and the Columbia River Flood Basalt Province, USA. No single outcrop provides a definitive analogy to Rosebank, but each offers insights that provide an important link to understanding and managing the main subsurface uncertainties associated with field development. Integration of these multiple workflows have improved the reservoir characterization and provided the foundation for the optimization of the field development plan.

scholarly journals Streamline-Based Time-Lapse-Seismic-Data Integration Incorporating Pressure and Saturation Effects

SPE Journal ◽  
2017 ◽  
Vol 22 (04) ◽  
pp. 1261-1279 ◽  
Author(s):  
Shingo Watanabe ◽  
Jichao Han ◽  
Gill Hetz ◽  
Akhil Datta-Gupta ◽  
Michael J. King ◽  
...  
Keyword(s):  
High Resolution ◽  
Finite Difference ◽  
Seismic Data ◽  
History Matching ◽  
Flow Simulation ◽  
Time Lapse ◽  
Production Data ◽  
Reservoir Properties ◽  
Fluid Saturation ◽  
Saturation Effects

Summary We present an efficient history-matching technique that simultaneously integrates 4D repeat seismic surveys with well-production data. This approach is particularly well-suited for the calibration of the reservoir properties of high-resolution geologic models because the seismic data are areally dense but sparse in time, whereas the production data are finely sampled in time but spatially averaged. The joint history matching is performed by use of streamline-based sensitivities derived from either finite-difference or streamline-based flow simulation. For the most part, earlier approaches have focused on the role of saturation changes, but the effects of pressure have largely been ignored. Here, we present a streamline-based semianalytic approach for computing model-parameter sensitivities, accounting for both pressure and saturation effects. The novelty of the method lies in the semianalytic sensitivity computations, making it computationally efficient for high-resolution geologic models. The approach is implemented by use of a finite-difference simulator incorporating the detailed physics. Its efficacy is demonstrated by use of both synthetic and field applications. For both the synthetic and the field cases, the advantages of incorporating the time-lapse variations are clear, seen through the improved estimation of the permeability distribution, the pressure profile, the evolution of the fluid saturation, and the swept volumes.

scholarly journals Time-lapse full-waveform inversion with ocean-bottom-cable data: Application on Valhall field

Geophysics ◽  
2016 ◽  
Vol 81 (4) ◽  
pp. R225-R235 ◽  
Author(s):  
Di Yang ◽  
Faqi Liu ◽  
Scott Morton ◽  
Alison Malcolm ◽  
Michael Fehler
Keyword(s):  
Seismic Data ◽  
Waveform Inversion ◽  
Time Lapse ◽  
Double Difference ◽  
Baseline Survey ◽  
Data Sets ◽  
Full Waveform Inversion ◽  
Ocean Bottom ◽  
Full Waveform ◽  
Future Production

Knowledge of changes in reservoir properties resulting from extracting hydrocarbons or injecting fluid is critical to future production planning. Full-waveform inversion (FWI) of time-lapse seismic data provides a quantitative approach to characterize the changes by taking the difference of the inverted baseline and monitor models. The baseline and monitor data sets can be inverted either independently or jointly. Time-lapse seismic data collected by ocean-bottom cables (OBCs) in the Valhall field in the North Sea are suitable for such time-lapse FWI practice because the acquisitions are of a long offset, and the surveys are well-repeated. We have applied independent and joint FWI schemes to two time-lapse Valhall OBC data sets, which were acquired 28 months apart. The joint FWI scheme is double-difference waveform inversion (DDWI), which inverts differenced data (the monitor survey subtracted by the baseline survey) for model changes. We have found that DDWI gave a cleaner and more easily interpreted image of the reservoir changes compared with that obtained with the independent FWI schemes. A synthetic example is used to demonstrate the advantage of DDWI in mitigating spurious estimates of property changes and to provide cross validations for the Valhall data results.

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