Monument Butte field produces oil from 22 commingled sandstone reservoirs across a 2200-ft interval of the Green River formation. Total (primary and secondary) recovery is less than 10% of the OOIP. Green River formation sands are lenticular, lacustrine fluvial-deltaic units that have limited aerial extent and vertical communication, resulting in poor interwell connectivity. Moreover, the reservoirs sands have low permeability. To determine interwell connectivity and to identify methods to improve oil recovery, we conducted detailed reservoir characterization and simulation studies in a pilot area of Monument Butte field.We built a 3D geostatistical model and ranked geological realizations using production history matching with streamline simulation. Detailed petrophysical and geological modeling were used to quantify interwell connectivity of sands as a function of well spacing. Studies of interwell connectivity were also used to identify flow barriers that we applied in upscaled reservoir simulation models to better represent interwell connectivity. A combination of manual and assisted history matching methods was used to calibrate the reservoir model. Primary, secondary, and tertiary development strategies were then evaluated for future optimization of oil recovery for new developing areas in Monument Butte field.This study yielded a reservoir model much improved over those of previous studies. A good history match was obtained for most wells, despite the complexity of this stacked, heterogeneous reservoir system. Simulation results indicate that interwell connectivity has the greatest impact on reservoir performance. Interwell connectivity was demonstrated for only major sands, and interwell connectivity increases as well spacing decreases for these sands. A pilot 20-acre infill drilling study is needed to verify this conclusion. The overall connectivity for the combined 22 zones is 0.056 (connected adjacent well pairs divided by total adjacent well pairs). The connectivities for major sand zones evaluated by history matching are 0.65, 0.16, 0.23, and 0.01 for the D1 sand, C sands, A sands, and LODC sands, respectively. Simulation results indicate that reservoir performance can potentially be improved with various reservoir management strategies, including infill drilling. For new development areas, water flooding should start as soon as possible (within 6 months). Tertiary recovery methods may have potential in the Monument Butte field, given the low recovery efficiencies for primary and secondary recovery. Wateralternating-CO 2 injection appears to be superior to other tertiary recovery methods. Further evaluation and piloting of tertiary methods is required, given the connectivity risk. The target area study results can be used to guide the development of other parts of the large Monument Butte field.

TX 75083-3836, U.S.A., fax 01-972-952-9435. AbstractVertical permeability magnitude is critical to well trajectory and/or completion design whenever the oil is either overlain by a gas cap or underlain by an aquifer or whenever a slanted or horizontal well is planned. Various authors have provided ways to determine horizontal and vertical permeability from a pressure transient test in a well with a limited entry completion. However, none indicate a test design that will ensure that the vertical permeability can be determined.This paper provides the necessary test design considerations for horizontal and vertical permeability determination from a conventional pressure buildup test. A standard limited entry model for the pressure transient behavior is used to determine timing for the start and end of key flow regimes for the transient interpretation. Equations that can be used to design a test for vertical permeability determination are also used to indicate ranges of reservoir, fluid and well properties that result in a successful test.A quick look analysis procedure enables estimation of horizontal and vertical permeability directly from a log-log diagnostic plot of pressure change and its logarithmic derivative. Examples illustrate test design and interpretation applications and demonstrate that determination of vertical permeability is possible even when wellbore storage masks early radial flow and an overlying gas cap and/or underlying aquifer prevent the appearance of late radial flow.

TX 75083-3836, U.S.A., fax 01-972-952-9435. AbstractVertical permeability magnitude is critical to well trajectory and/or completion design whenever the oil is either overlain by a gas cap or underlain by an aquifer or whenever a slanted or horizontal well is planned. Various authors have provided ways to determine horizontal and vertical permeability from a pressure transient test in a well with a limited entry completion. However, none indicate a test design that will ensure that the vertical permeability can be determined.This paper provides the necessary test design considerations for horizontal and vertical permeability determination from a conventional pressure buildup test. A standard limited entry model for the pressure transient behavior is used to determine timing for the start and end of key flow regimes for the transient interpretation. Equations that can be used to design a test for vertical permeability determination are also used to indicate ranges of reservoir, fluid and well properties that result in a successful test.A quick look analysis procedure enables estimation of horizontal and vertical permeability directly from a log-log diagnostic plot of pressure change and its logarithmic derivative. Examples illustrate test design and interpretation applications and demonstrate that determination of vertical permeability is possible even when wellbore storage masks early radial flow and an overlying gas cap and/or underlying aquifer prevent the appearance of late radial flow.