Non-Linear Rock Compressibility in the Naricual and Los Jabillos Formations, El Furrial Field, Venezuela

Abstract

The discovery of the El Furrial field in 1986 opened a new era of exploration and development in the eastern Venezuela deep basin. Current production from the field and two adjacent fields, Carito and Santa Barbara, is near 900,000 stb/D (stock tank barrels per day). Reservoir simulation has been used consistently since 1989 for reservoir management. Water injection, initiated in 1993, was identified in 1991 as a necessary process to maintain reservoir pressure above a critical asphalt flocculation pressure. Reservoir pressure below the flocculation pressure (6500 psi for 2% asphaltene content up to 8500 psi for 12%) results in significant and irreversible well productivity decline. A previously unrecognized variable in the production mechanism, necessary for the history match of observed reservoir pressure after initiation of water injection, was identified with reservoir simulation modeling. Investigation of fluid compressibility, aquifer support, and rock compressibility, identified that this variable was more important than previously assumed. The method of analysis shows that standard Teeuw 1 rock compressibility analysis is not appropriate. The method proposed by Anderson2 does. This paper focuses on the rock compressibility issue, the analysis of the data, and the method to include the results in reservoir simulation. Introduction The El Furrial field is located in Monagas State, Venezuela, approximately 20 km. west of Maturin as shown in Fig. 1. It is associated with other fields along a trend of deep thrust structures. Other fields associated with the same trend are the Orocual and Boqueron fields to the east and north, and the Carito Complex and Santa Barbara field to the west. The field is approximately 13 km. along strike and 7 km wide. The field produces from two reservoirs identified as the Naricual and Los Jabillos Formations. The gross thickness of the two reservoirs is more than 1600 feet. El Furrial field is characterized as a giant field with original-oil-in-place (OOIP) in the Naricual formation estimated to be more than 6,000 billion stb. The field was discovered in 1986 with the exploratory well FUL-1. This well was drilled through the top of the Naricual Formation, discovering medium gravity oil with an API gravity of 16° to 28° and a highly under-saturated GOR from 500 to 800 scf/stb. The initial reservoir pressure of 11020 psi, corrected to datum at 13000 feet sub sea (measured depth of approximately 13500 feet) indicated significant over-pressured conditions. Pressure data taken after water injection was started showed anomalous pressure response as predicted by material balance analysis and simulation. Figs. 2 and 3 show the original prediction of reservoir pressure for the Naricual Superior and Inferior units. Highlighted in these graphs is the departure from the observations of the simulated decline after water injection was started. The effect is more pronounced in Figure 3 in Naricual Inferior. It was determined that initial depletion of the reservoir was affected by high values of rock compressibility because of the original over-pressured reservoir condition. Naricual formation whole core was tested for rock compressibility. These data were analyzed and results show that especially at early time of production and development, where net effective overburden stress is low, the rock compressibility is non-linear and high (> 10*10 -6 psi/psi). The use and incorporation of this data in reservoir simulation is important in the history match and has a direct effect on the material balance and fluid-in-place evaluation. Rock compressibility, previously assumed to be constant (˜3*10-6 psi/psi) through the total range of reservoir pressure, shows a high initial non-linear compressibility with linear compressibility occurring after a certain net overburden stress is reach (˜4000–5000 psi). Understanding the importance of this factor in the depletion mechanism of the field is critical to reservoir management.

Study on Reasonable Energy Supplement Time of Tight Sandstone Oil Reservoirs with Rock Compressibility Stress Sensitivity

“…(2) A new approach is presented to predict energy supplement time of tight sandstone oil reservoirs. This new approach takes threshold pressure gradient and rock compressibility stress sensitivity into account 4 Geofluids…”

“…As a result, the rock compressibility decreases (Figure 3) because of the stress sensitivity. Integrating (2) with respect to formation pressure and distance yields the elastic cumulative oil production in drainage volume (4).…”

“…The original formation pressure is 50 MPa. Tight oil reservoirs have obvious threshold pressure gradient characters [1][2][3] and rock compressibility stress sensitivity characters [4][5][6][7]. The formation water is going to salt out and solution gas is going to get out from the oil if formation pressure decreases fast.…”