Integrated Wellbore Analysis – Well 4-BRSA-1047-RJS

Petrophysical and PVT analyses, integrated with logging and formation test analyses, are key to providing essential input for reservoir characterization, dynamic flow simulation and reservoir management.

The BPS Geodatabase includes a comprehensive collection of reservoir data that are applied to:

  • Rock properties such as permeability, porosity, capillary pressure, relative permeabilities, net and gross pay and water saturation, among others, obtained from laboratory analysis of core plugs and sidewall-rock samples and petrophysics logging.
  • Fluid properties such as oil and gas densities, bubble point pressure, formation volume factors, oil solubility and fluid composition obtained from PVT analysis.
  • Properties such as static reservoir pressure, well productivity, reservoir fluid gradient and hydrocarbon-water contacts obtained from wireline formation test and drill stem test.

Using these datasets for key wells in the Santos and Campos basins, integrated wellbore analysis highlights important features of the reservoirs such as the presence of naturally fractured systemshydraulic continuity in all intervals of the producing formations, evidence of oil wettability in the carbonate reservoirs and the occurrence of compositional grading when the hydrocarbon fluids have very high CO2 content.

To illustrate these features in the reservoirs of the Santos Basin, the application of integrated wellbore analysis for well 4-BRSA-1047-RJS is presented below.

Well Location

The well was drilled in the Transfer of Rights area of the Brazilian pre-salt, which is operated by Petrobras in accordance with the new regulatory regime created in 2010 to grant licences to the Brazilian oil major to produce up to 5 billion boe in the Buzios field and surrounding areas. After appraisal, the well became part of the South Lula Field, located in the central portion of the Santos Basin at a water depth of 2,182 m (7,157 ft.) and around 230 km (143 mi.) from the coast of Rio de Janeiro,  as shown in Figure 1.

Drilling ended in April 2013, reaching a final depth of 5,328.5 m (17477.5 ft). High quality carbonate reservoirs (Aptian age) were found in the Barra Velha Formation, in a very thick interval of almost 270 m (886 ft.).

Figure 1 – Well location in South Tupi Field

Petrophysical Analysis

Laboratory experiments were performed on core plugs and sidewall-rock samples from the shallower zone of the reservoir to measure basic petrophysical properties (absolute permeability, porosity, rock density and confining pressure) and special properties (relative permeabilities and capillary pressure).

The influence of reservoir heterogeneities in the petrophysical properties have been observed in several samples, particularly because of the unusual permeability-porosity characteristics of the reservoir rocks, showing some zones with high permeability and relatively low porosities. This petrophysical behavior results from the existence of a regional network of fractures, microfractures and vugs in all the carbonate facies, characterizing a naturally fractured system.

This anomalous behavior can be seen in the depth-permeability graph depicted in Figure 2 and the depth-porosity graph shown in Figure 3, where the core plugs with permeability greater than 100 mD and porosity lower than 15% are highlighted.

Figure 2 – Depth-permeability graph showing the anomalous behavior of the rock properties measured in core plugs
Figure 3 – Depth-porosity graph showing the anomalous behavior of the rock properties measured in core plugs

The same characteristics can be observed for the rock properties from the sidewall-rock samples, as shown in the depth-permeability graph in Figure 4 and the depth-porosity graph in Figure 5.

Figure 4 – Depth-permeability graph showing the anomalous behavior of behavior of the rock properties measured in sidewall-rock samples
Figure 5 – Depth-porosity graph showing the anomalous behavior of behavior of the rock properties measured in sidewall-rock samples

Permeability and porosity evaluation by petrophysical logging also confirm this anomalous behavior, as shown in Figure 6, where the rock properties were determined by Nuclear Magnetic Resonance (NMR) logging.

Figure 6 – Petrophysical properties determined by NMR logging –  Well 1-BRSA-1047-RJS

Relative permeability measurements of core plugs collected at three different depths have presented the following end-point parameters:

where:

k = base permeability          kro @ Swir =  oil relative permeability at Swir 
Ф = effective porosity          ko @ Swir =  oil effective permeability at Swir
Swir = irreducible H20 sat.   krw @ S0r = water relative permeability at Sor
Sor = residual oil sat.           kw @ S0r =  water effective permeability at Sor

The normalized water-oil relative permeability curves for the plugs at the same depths are depicted in Figure 7.

Figure 7 – Normalized water-oil relative permeabilities – Well 4-BRSA-1047-RJS, where: SwD = dimensionless water saturation; Kro(SwD) = normalized oil relative permeability; Krw(SwD) = normalized water relative permeability; and SwD = Sw – Swir / 1 – Swir – Sor

Note that the intersection points of the relative permeability curves have water saturation of less than 50%, which is strong evidence of oil wettability in the microbialite reservoirs of the field. 

Irreducible water saturation ranges from 22.3% to 30.5% and residual oil saturation from 5.7% to 17.4%, as observed in the table of the end-point relative permeabilities.

Capillary pressure measurements using the centrifuge method have also been analysed, with the results shown in Figure 8.

Figure 8 – Cappillary pressure measurements

The capillary curves obtained for samples at three different depths show the irreducible water saturations ranging from 23.6% to 28.9%, which is in line with the range obtained by the relative permeability measurements.

Formation Evaluation

The static reservoir pressure obtained by the bottomhole sidewall-rock measurement at different depths of the shallower zone of the Barra Velha Formation is plotted in Figure 9. The linear relationship between the reservoir pressure and depth in a thick interval of 93 m (305 ft) is a clear indication of hydraulic continuity in the entire zone.

Oil-water contact was identified at a depth of 5,143 m (16869 ft). The pressure gradient is 0.074 kgf/cm2/m (0.321 psi/ft) in the oil zone and 0,110 kgf/cm2/m (0,477 psi/ft) in the water zone.

Figure 9 – Reservoir pressure gradiente – Well 4-BRSA-1047-RJS

The oil gravities for fluid samples at four different depths, measured from the top to the bottom of the oil zone, are very close to each other (26.5 °API on average), as shown by the yellow dots in Figure 9. This indicates a lack of gravity segregation in the reservoir. A plausible explanation for the oil homogenetization in the large interval may lie in the effect of natural thermal convection in the entire naturally fractured system.

The well test analysis of the drill stem test (DST) executed in the interval of 5,060m (16,597 ft) to 5,122 m (16800 ft) provided the following results:

The oil gravity measured by the DST was 28.8 °API, which is a little higher than the measurements of the wireline formation test. The Gas-Oil Ratio (GOR) was 210 std m³/std m³. No water production was observed.

The CO2 content was 18%, obtained from the compositional analysis of the separated gas, performed on the drilling rig.

PVT Analysis

The PVT analysis was performed with oil samples collected during the DST. The compositional analysis of the oil, gas and reservoir fluid is shown in Figures 10, 11, and 12, respectively.

Figure 10 – Oil compositional analysis – Well 4-BRSA-1047-RJS
Figure 11 – Gas compositional analysis – Well 4-BRSA-1047-RJS
Figure 12 – Reservoir fluid compositional analysis – Well 4-BRSA-1047-RJS

The CO2 content in the gas phase was 17.05%, which is very consistent with the DST measurement. On the other hand, the reservoir fluid holds CO2 content of 12.9%.

The oil gravity is 27.15 °API and the reservoir temperature is 62.2 °C.

The bubble point pressure was 375.6 kgf/cm² (5341 psia), showing a fairly high degree of undersaturation based on the initial reservoir pressure of 553.3 kgf/cm² (7868 psia) obtained by the DST.

The primary PVT properties (formation volume factors of oil and gas and solubility ratio) are shown in Figures 13 to 15.

Figure 13 – Oil formation volume factor – relationship with pressure below and above bubble point
Figure 14 – Gas formation volume factor for the gas liberated below bubble point
Figure 15 – Solubility ratio – constant above bubble point and declining below bubble point

The stabilized GOR after flash liberation was 282.8 std m³/std m³ (1588 scf/stb), contrasting with the solubility ratio of 235.9 (1323 scf/stb), above the bubble point. 

The relationships of oil and gas density and viscosity with pressure, as well as the Z gas compressibility factor,  are also provided in tables in the BPS Geodatabase.

Final Remarks
 A better understanding of the rock and fluid characteristics of the the carbonate reservoirs of the Barra Velha Formation in Santos Basin can be achieved via integrated wellbore analysis using data from laboratory petrophysics, logging, formation evaluation and PVT.

The analysis of petrophysical data available in the BPS Geodatabase has shown strong evidence that the producing zones of the microbialite carbonates behave as a naturally fractured system.

Moreover, the relative permeability measurements indicate that the producing zones show oil wettability.

The irreducible water saturation determined by the relative permeability experiments and the centrifuge capillary pressure method are in line with each other.

The pressure gradient determination from the wireline formation test confirms hydraulic continuity across the whole oil producing zone, which can be seen as an effect of the naturally fractured system.

The PVT analysis provides the fluid composition and the PVT parameters that are essential for resource evaluation and dynamic flow simulation.

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