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.

Petrophysical interpretation and fluid substitution modelling of the upper shallow marine sandstone reservoirs in the Bredasdorp Basin, offshore South Africa

The fluid substitution method is used for predicting elastic properties of reservoir rocks and their dependence on pore fluid and porosity. This method makes it possible to predict changes in elastic response of a rock saturation with different fluids. This study focused on the Upper Shallow Marine sandstone reservoirs of five selected wells (MM1, MM2, MM3, MM4, and MM5) in the Bredasdorp Basin, offshore South Africa. The integration of petrophysics and rock physics (Gassmann fluid substitution) was applied to the upper shallow marine sandstone reservoirs for reservoir characterisation. The objective of the study was to calculate the volume of clay, porosity, water saturation, permeability, and hydrocarbon saturation, and the application of the Gassmann fluid substitution modelling to determine the effect of different pore fluids (brine, oil, and gas) on acoustic properties (compressional velocity, shear velocity, and density) using rock frame properties. The results showed average effective porosity ranging from 8.7% to 16.6%, indicating a fair to good reservoir quality. The average volume of clay, water saturation, and permeability values ranged from 8.6% to 22.3%, 18.9% to 41.6%, and 0.096–151.8 mD, respectively. The distribution of the petrophysical properties across the field was clearly defined with MM2 and MM3 revealing good porosity and MM1, MM4, and MM5 revealing fair porosity. Well MM4 revealed poor permeability, while MM3 revealed good permeability. The fluid substitution affected rock property significantly. The primary velocity, Vp, slightly decreased when brine was substituted with gas in wells MM1, MM2, MM3, and MM4. The shear velocity, Vs, remained unaffected in all the wells. This study demonstrated how integration of petrophysics and fluid substitution can help to understand the behaviour of rock properties in response to fluid saturation changes in the Bredasdorp Basin. The integration of these two disciplines increases the obtained results’ quality and reliability.

Elastic moduli of dry and water-saturated carbonates — Effect of depositional texture, porosity, and permeability

Elastic moduli of water-saturated sedimentary rocks are in some cases different from moduli derived using Gassmann fluid substitution on data for rocks in the dry state. To address this discrepancy, we use a data set representing 115 carbonate samples from different depositional settings and a wide range of porosity and permeability. Depositional texture is reflected in the effect of water on elastic moduli and in the porosity-permeability relationship. Depositional texture is taken into account when porosity and permeability are combined in the effective specific surface of pores, which is related for a given pore fluid to the reference frequency as defined by Biot. For a given frequency of elastic waves, we obtain Biot’s frequency ratio between measured ultrasonic wave frequency and Biot reference frequency. For mostsamples with a frequency ratio above 10, elastic moduli in the water-saturated case are higher than predicted from elastic moduli in the dry case by Gassmann fluid substitution. This stiffening effect of water in some cases may be described by Biot’s high-frequency model, although in heterogeneous samples, a squirt mechanism is more probable. For data representing frequency ratios of 0.01 to 1, Gassmann fluid substitution works well. For samples with frequency ratios below 0.001, elastic moduli in the water-saturated case are lower than would be expected according to Gassmann’s equations or to Biot’s theory. This water-softening effect becomes stronger with decreasing frequency ratio. Water softening or stiffening of elastic moduli may be addressed by effective-medium modeling. In this study, we used the isoframe model to quantify water softening as a function of frequency ratio.