Fracture Impact on Reservoir Performance near Fault Damage Zone

Abstract

Fault Damage zone are known to have complex fault geometry with abundant presence of natural fracture ranging from cores to outcrops scale. The distribution of those fractures correlates with the width of the fault, observed displacement, faulting mechanism, and the formation thickness and properties. As many faults can act as barriers or conduit, natural fractures on the reservoir scale can be open conduit for fluid, hydrocarbon or water, or cemented and calcite filled. Answering those questions impacts reservoir development plans in regards to well placement, landing zone, and completion strategy. This paper presents a study for two reservoirs, a silica and clay rich, tight, thin shale reservoir overlain by a thick, dolomitic, and brittle carbonate reservoir. Both of those formations have low permeability and are hydrocarbon bearing such that staggering wells are needed to maximize reservoir production. The study area is within the vicinity of a major fault line that runs north to south on the east of the field. No other faults have been seen or mapped within the field. However, the carbonate reservoir is highly fractures with some conductive and other resistive faults. The fracture density in the shale layer is extremely low with the majority of those fractures being completely closed. The work consisted of studying the variation of facies along the lateral and the relation of fracture density and facies within the carbonate layers. Facies were examined using image log data coupled with mud log data and cuttings information. After examining the fracture density for multiple wells in the area, a map showing the distribution of natural fractures indicates a decrease of fracture density away from the fault line. The density correlates with the distance to the fault line. Knowing the distribution, a statistical model was used to populate the fracture in a 3D reservoir model such that those fractures are assumed to increase reservoir permeability. The static model is then moved to dynamic simulation to study the communication impact that those fractures have on the production. It was observed that natural fracture contributes significantly to the well productivity. With higher fracture density, the carbonate reservoir drains more efficiently than the shale formation. In lateral direction, well drainage area correlates with spatial variation of fracture density, indicating potentially different optimal well spacing from east to west part of the field. Consequently, Inter-well interference is expected to be more pronounced on the east side than the west side of the field. In addition, sensitivity studies show that wells landing in shale are able to drain both formations effectively, given that hydraulic fractures propagate upward into carbonate formation associated with dense natural fractures.

AAPG Datapages/Search and Discovery Article #90335 © 2018 AAPG 47th Annual AAPG-SPE Eastern Section Joint Meeting, Pittsburgh, Pennsylvania, October 7-11, 2018