Wellbore Stability Simulations for Underbalanced Drilling Operations in Highly Depleted Reservoirs
- J.G. Parra (PDVSA-INTEVEP) | E. Celis (PDVSA-INTEVEP) | S. De Gennaro (PDVSA-INTEVEP)
- Document ID
- Society of Petroleum Engineers
- SPE Drilling & Completion
- Publication Date
- June 2003
- Document Type
- Journal Paper
- 146 - 151
- 2003. Society of Petroleum Engineers
- 5.6.1 Open hole/cased hole log analysis, 1.2.2 Geomechanics, 5.3.1 Flow in Porous Media, 4.1.2 Separation and Treating, 1.11 Drilling Fluids and Materials, 2.4.3 Sand/Solids Control, 1.8 Formation Damage, 1.7.7 Cuttings Transport, 1.6 Drilling Operations, 4.3.4 Scale, 1.11.2 Drilling Fluid Selection and Formulation (Chemistry, Properties), 7.7.1 New Technology Deployment, 4.1.5 Processing Equipment, 1.7.1 Underbalanced Drilling
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The need to increase productivity and to reduce drilling formation damage favors the use of underbalanced drilling technology. The main idea is to drill with equivalent circulating densities (ECD) that are less than the formation pore pressure and to avoid contact between the drilling fluid and the formation. In highly depleted reservoirs, pore pressures can be very low. Therefore, extremely low-density fluids, such as foams, are used to achieve circulating densities lower than the pore pressure. In such cases, the induced modification of the in-situ stresses has to be supported mainly by the rock, with little contribution from the drilling fluid pressure. In that sense, the application of underbalanced drilling depends on the mechanical stability of the drilled formation, among other factors. In general, poorly consolidated, depleted formations are not suited for that technology. This paper presents the wellbore stability simulation performed to establish the feasibility of using underbalanced drilling in highly depleted reservoirs in western Venezuela. The in-situ stress field and the mechanical properties of the formation were obtained. Pore pressure as low as 800 psi at 5,500 ft (2.7 lb/gal equivalent fluid density) was measured. The finite difference method and an elastoplastic constitutive model was used to obtain the new stress, deformation, and pore pressure distribution. The undrained condition (immediately after the wellbore is drilled) as well as the drained condition were analyzed. The analysis showed that horizontal wells could be drilled in an underbalanced condition with low instability risk. Following the recommendations, four horizontal wells were drilled in underbalanced conditions. Values as low as 2.0 lb/gal ECD were used to drill the wells, and no wellbore instability problems were reported. Production tests showed an enormous increase in the well productivity index in comparison with conventional overbalanced drilling.
Years of crude exploitation can lead to enormous reservoir pressure decline in mature fields, leaving a huge amount of oil still in place that can only be exploited with new technologies. Once a mature field has reached an extremely low pore pressure, the target formation should be drilled in an underbalanced condition (with a drilling fluid pressure of less than the formation pore pressure) to reduce the risk of lost circulation, and most importantly, to reduce formation damage and increase productivity. Pore pressures as low as 800 psi at 5,500 ft true vertical depth (TVD) have been measured in matured fields. This is equivalent to a hydrostatic column of drilling fluid of 2.7 lb/gal density. To reach the underbalanced drilling condition in such a depleted reservoir, the ECD of the drilling fluid must be less than 2.7 lb/gal. Conventional drilling fluids are out of this range; therefore, the use of low-density drilling fluids, such as foams, is needed.
Drilling fluids must provide good cuttings transport, among other things. In addition, when the hole is drilled, the in-situ original stresses change near the wellbore, and the drilling fluid pressure (or density) must somehow "replace" the support lost by removing the original volume of rock. In conventional overbalanced drilling, the drilling fluid pressure (or density) is usually high enough to provide this support. On the other hand, it is necessary to establish whether low-density fluids used for underbalanced drilling in highly depleted reservoirs will provide the pressure needed by the formation to keep it stable. If not, underbalanced drilling is not technically possible, and the minimum drilling fluid density (and pressure) will be established by the formation minimum collapse pressure obtained with rock-mechanics approaches.
The main scope of this paper is to present the wellbore stability simulations performed in a highly depleted reservoir in Lake Maracaibo, Venezuela, to decide the feasibility of using underbalanced drilling technology. The field behavior of four wells drilled in underbalanced conditions is summarized. Benefits such as increase of rate of penetration, no drilling time lost because of lost circulation or stuck pipe, and most importantly, huge productivity increases were obtained in comparison with conventional overbalanced drilling.
Background and Technological Challenge
Many horizontal wells in a highly depleted reservoir in western Venezuela were drilled in an overbalanced and near-balanced condition, at pressures greater than the in-situ reservoir pore pressure. Lost-circulation problems and stuck pipes raised drilling costs, reducing the project's profitability. In addition, the expected productivity increases were seldom reached. Therefore, real underbalanced drilling technology was proposed to increase reservoir productivity. The challenge for the rock-mechanics team was to define the risk of wellbore instability when drilling in an underbalanced condition with ECDs as low as 2.0 lb/gal. In such a condition, the rock must be sufficiently strong to resist most of the redistributed stresses. Technology implementation was decided based on wellbore stability calculations and results.
Rock Mechanics Data
Wellbore stability in sandstone depends on many factors, such as wellbore geometry (azimuth, inclination, and diameter), current formation pore pressure, original in-situ field stress (magnitude and direction), geomechanical properties of the rock (including its geological particularities), and the ECD. Well geometry and drilling fluid density may be selected to reduce wellbore stability problems, such as high deformations, wellbore breakouts, washouts, and lost circulation caused by induced drilling fractures.
Acoustic image logs, multipolar sonic logs, six arm-oriented caliper logs, density logs, minifrac tests, and rock mechanical laboratory tests on rock cores were used to obtain the required information for stability analysis.
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