Safeguarding CO2 Storage in a Depleted Offshore Gas Field with Adaptive Approach of Monitoring, Measurement and Verification MMV

CO2 sequestration is a process for eternity with a possibility of zero-degree failure. One of the key components of the CO2 Sequestration Project is to have a site-specific, risk-based and adaptive Monitoring, Measurement and Verification (MMV) plan. The storage site has been studied thoroughly and is understood to be inherently safe for CO2 sequestration. However, it is incumbent on operator to manage and minimize storage risks. MMV planning is critical along with geological site selection, transportation and storage process. Geological evaluation study of the storage site suggests the containment capacity of identified large depleted gas reservoirs as well as long term conformance due to thick interval. The fault-seal analysis and reservoir integrity study contemplate long-term security of the CO2 storage. An integrated 3D reservoir dynamic simulation model coupled with geomechanical and geochemical models were performed. This helps in understanding storage capacity, trapping mechanisms, reservoir integrity, plume migration path, and injectivity. To demonstrate that CO2 plume migration can be mapped from the seismic, a 4D Seismic feasibility study was carried out using well and fluid data. Gassmann fluid substitution was performed in carbonate reservoir at well, and seismic response of several combination of fluid saturation scenarios on synthetic gathers were analyzed. The CO2 dispersion study, which incorporate integration of subsurface, geomatic and metocean & environment data along with leakage character information, was carried out to understand the potential leakage pathway along existing wells and faults which enable to design a monitoring plan accordingly. The monitoring of wells & reservoir integrity, overburden integrity will be carried out by Fiber Optic System to be installed in injection wells. Significant difference in seismic amplitude observed at the reservoir top during 4D seismic feasibility study for varying CO2 saturation suggests that monitoring of CO2 plume migration from seismic is possible. CO2 plume front with as low as 25% saturation can be discriminated provided seismic data has high signal noise ratio (SNR). 3D DAS-VSP acquisition modeling results show that a subsurface coverage of approximately 3 km2 per well is achievable. Laboratory injectivity studies and three-way coupled modelling simulations established that three injection wells will be required to achieve the target injection rate. As planned injection wells are field centric and storage site area is large, DAS-VSP find limited coverage to monitor the CO2 plume front. Hence, surface seismic acquisition will be an integral component of full field monitoring and time-lapsed evaluations for integrated MMV planning to monitor CO2 plume migration. The integrated MMV planning is designed to ensure that injected CO2 in the reservoir is intact and safely stored for hundreds of years after injection. Field specific MMV technologies for CO2 plume migration with proactive approach were identified after exercising pre-defined screening criteria.

3D DAS-VSP Illumination Modeling for CO2 Plume Migration Monitoring in Offshore Sarawak, Malaysia

Monitoring of CO2 plume migration in a depleted carbonate reservoir is challenging and demand comprehensive and trailblazing monitoring technologies. 4D time-lapse seismic exhibits the migration of CO2 plume within geological storage but in the area affected by gas chimney due to poor signal-to-noise ratio (SNR), uncertainty in identifying and interpretation of CO2 plume gets exaggerated. High resolution 3D vertical seismic profile (VSP) survey using distributed acoustic sensor (DAS) technology fulfil the objective of obtaining the detailed subsurface image which include CO2 plume migration, reservoir architecture, sub-seismic faults and fracture networks as well as the caprock. Integration of quantitative geophysics and dynamic simulation with illumination modelling dignify the capabilities of 3D DAS-VSP for CO2 plume migration monitoring. The storage site has been studied in detailed and an integrated coupled dynamic simulation were performed and results were integrated with seismic forward modeling to demonstrate the CO2 plume migration with in reservoir and its impact on seismic amplitude. 3D VSP illumination modelling was carried out by integrating reservoir and overburden interpretations, acoustic logs and seismic velocity to illustrate the subsurface coverage area at top of reservoir. Several acquisition survey geometries were simulated based on different source carpet size for effective surface source contribution for subsurface illumination and results were analyzed to design the 3D VSP survey for early CO2 plume migration monitoring. The illumination simulation was integrated with dynamic simulation for fullfield CO2 plume migration monitoring with 3D DAS-VSP by incorporating Pseudo wells illumination analysis. Results of integrated coupled dynamic simulation and 4D seismic feasibility were analyzed for selection of best well location to deploy the multi fiber optic sensor system (M-FOSS) technology. Amplitude response of synthetic AVO (amplitude vs offsets) gathers at the top of carbonate reservoir were analyzed for near, mid and far angle stacks with respect to pre-production as well as pre-injection reservoir conditions. Observed promising results of distinguishable 25-30% of CO2 saturation in depleted reservoir from 4D time-lapse seismic envisage the application of 3D DAS-VSP acquisition. The source patch analysis of 3D VSP illumination modelling results indicate that a source carpet of 6km×6km would be cos-effectively sufficient to produce a maximum of approximately 2km in diameter subsurface illumination at the top of the reservoir. The Pseudo wells illumination analysis results show that current planned injection wells would probably able to monitor early CO2 injection but for the fullfield monitoring additional monitoring wells or a hybrid survey of VSP and surface seismic would be required. The integrated modeling approach ensures that 4D Seismic in subsurface CO2 plume monitoring is robust. Monitoring pressure build-ups from 3D DAS-VSP will reduce the associated risks.

4D Seismic Detectability in a Brazilian Pre-Salt Carbonate Field

This paper is dedicated to a pre-salt carbonate field located within the Santos Basin, Brazil, comprising thick Aptian reservoirs interspersed with igneous rocks. One of the main challenges for reservoir management is the surface constraint on the gas, as all of the produced gas will have to be reinjected and can be miscible with the in-situ hydrocarbons. The recovery mechanism selected is mainly WAG (water alternating gas) injection, with both producers and injectors equipped with intelligent completions using Inflow Control Valves (ICVs). A 4D seismic monitoring survey is planned to delineate gas and water fronts in reservoir flow units about 10m thick, providing critical information to help piloting a planned 6-month WAG cycle for improved recovery. Seismic imaging is challenging in this case and 4D signal is expected to be weak (±2% dIp/Ip). We propose here, a methodology, based on a 1-D Gassmann fluid substitution model at wells (only limited reservoir fluid PVT data available) to rapidly answer the following pertinent questions as posed by the asset team in charge of the field: From a phenomenological stand-point and neglecting some possible processing, imaging and acquisition challenges, will 4D data (post 4D inversion) detect a gas streak from an injector to a producer? What is the 4D seismic detection limit based on reservoir thickness? What kind of seismic acquisition will assure this detectability? Under the assumptions made in this work, this methodology shows that a permanent system of acquisition seems to be a fit-for-purpose technology for detectability. Further work is however recommended using full complement of a 3D static and dynamic simulation model coupled with a complete fluid PVT model in order to assess more complex 3D dynamic interactions between the injectors and producers.

Petroelastic Model PEM for a Highly Heterogeneous Cretaceous Reservoir in Middle East

The objective of this project is to simulate elastic logs (sonic P, sonic S and density) through a Petroelastic Model (PEM) for a complex lithology reservoir in the Middle East, that later will be used as input for a new 4D seismic feasibility study. A log conditioning (despike, depth shift, hydrocarbon correction and normalization) and comprehensive petrophysical analysis was first performed, to obtain lithology volumetric, porosity and saturation, that later were used as input for the PEM. Some wells with recorded P and S sonic log were used to conduct different cross plots of elastic properties (e.g. Vp/Vs vs. Acoustic Impedance) in order to understand how lithology, porosity and saturation affect the elastic parameters of the reservoir. After understanding and assessing the elastic behavior with the reservoir properties, three approaches to construct a PEM were tested on this reservoir. The first approach used to construct PEM applying Hashin Shtrikman (H-S) mixt, considering the solid part as a mixture of dolomite and limestone and pore space filled with a mix of oil and water. This model is limited because assumes a homogenous geometry of the pores. To address the pore geometry a Kuster Toksoz (K-T) approach was subsequently tested but the challenge was that there was no clear organization of the aspect ratio (either by lithofacies or petrophysical groups) so the original logs were used to control of the aspect ratio trough a fit function. The third approach was to use a function that models the incompressibility model of the frame (Kdry) with porosity. The result of H-S was a good agreement in the low porosity areas but in the porous intervals, it is observed that the velocities were quite high due the effect of the pore geometry that was not properly assessed by H-S. Despite reasonable reconstructions, K-T was limited by the impossibility to apply it to the wells without sonic P and S (uncalibrated aspect ratio) or a fortiori to a 3D grid. For the Kdry vs. Porosity function the result was very successful since the function is not dependent on the pore geometry, and addresses the ratio issue between solid and pore space. Then with the help of the Gassman Equation, the final Incompressibility Mix Module (Kmix) was calculated and a reconstructed sonic P and S were available for all the wells. The PEM was coded in order to deploy over a 3D property model hence a volumetric elastic model was available to assess the feasibility for new seismic acquisition.

Subaqueous geomorphology and delta dynamics of Lake Brienz (Switzerland): implications for the sediment budget in the alpine realm

Non-invasive techniques such as seismic investigations and high-resolution multibeam sonars immensely improved our understanding of the geomorphology and sediment regimes in both the lacustrine and the marine domain. However, only few studies provide quantifications of basin wide-sediment budgets in lakes. Here, we use the combination of high-resolution bathymetric mapping and seismic reflection data to quantify the sediment budget in an alpine lake. The new bathymetric data of Lake Brienz reveal three distinct geomorphological areas: slopes with intercalated terraces, a flat basin plain, and delta areas with subaquatic channel systems. Quasi-4D seismic reflection data allow sediment budgeting of the lake with a total sediment input of 5.54 × 106 t sediment over 15 years of which three-quarter were deposited in the basin plain. Lake Brienz yields extraordinarily high sedimentation rates of 3.0 cm/yr in the basin plain, much more than in other Swiss lakes. This can be explained by (i) its role as first sedimentary sink in a high-alpine catchment, and by (ii) its morphology with subaquatic channel-complexes allowing an efficient sediment transfer from proximal to distal areas of the lake.

Tupi Nodes pilot: A successful 4D seismic case for Brazilian presalt reservoirs

The oil and gas industry has established 4D seismic as a key tool to maximize oil recovery and operational safety in siliciclastic and low- to medium-stiffness carbonate reservoirs. However, for the stiffer carbonate reservoirs of the Brazilian presalt, the value of 4D seismic is still under debate. Tupi Field has been the stage of a pioneering 4D seismic project to field test the time-lapse technique's ability in monitoring production and water-alternating-gas (WAG) injection in the Brazilian presalt. Ocean-bottom node (OBN) technology was applied for the first time in the ultra-deep waters of Santos Basin, leading to the Tupi Nodes pilot project. We started with feasibility studies to forecast the presalt carbonate time-lapse responses. The minerals that constitute these carbonate rocks have an incompressibility modulus that is generally twice as large as those of siliciclastic rocks. This translates into discrete 4D signals that require enhanced seismic acquisition and processing techniques to be correctly detected and mapped. Consequently, two OBN seismic acquisitions were carried out. Time-lapse processing included the application of top-of-the-line processing tools, such as interbed multiple attenuation. The resulting 4D amplitude images demonstrate good signal-to-noise ratio, supporting both static and dynamic interpretations that are compatible with injection and production histories. To unlock the potential of 4D quantitative interpretation and the future employment of 4D-assisted history-matching workflows, we conducted a 4D seismic inversion test. Acoustic impedance variations of about 1.5% are reliably distinguishable beyond the immediate vicinity of the wells. These 4D OBN seismic surveys and interpretations will assist in identifying oil-bypassed targets for infill wells and calibrating WAG cycles, increasing oil recovery. We anticipate that studies of the entire Brazilian presalt section will greatly benefit from the results and conclusions already reached for Tupi Field.

The problem of using normalized rms in a sliding window to compare seismic tracesDISCUSSIONOn: “Imaging the Aquistore reservoir after 36 kilotonnes of CO2 injection using distributed acoustic sensing.” Harris, K., White, D.J., Samson, C., 2017. Geophysics 82 (6), M81–M96and “Initial 4D seismic results after CO2 injection start-up at the Aquistore storage site.” Roach, L.A.N., White, D.J., Roberts, B., Angus, D., 2017. Geophysics 82 (3), B95–B107.

Two papers published in Geophysics use the normalized rms (NRMS) calculation in a sliding window to compare traces and to create a ‘difference nrms’ volume. The authors use the derived difference volume to show the presence of apparent time-lapse anomaly between two seismic surveys. In this discussion we point out that the used methodology does not allow a robust comparison of seismic traces. We recommend the use of simple amplitude difference calculation between volumes to show the presence of time-lapse anomalies, instead of the used methodology.