Frac Design Learnings from a Tight Sandstone Formation in Saudi Arabia

Abstract

Cross-linked polymer has been utilized in the past to hydraulically treat the unconventional tight gas formations even though it has varying pay zone thickness that exhibits inconsistent lower stress barriers due to heterogeneities features of the field. Some of these reservoirs are connected with underlying water zones that have high potential to interaction with propped fractures due to absence of both clear stress barrier and inadequate net pressure which results in high water production. Petro-physical logs are analyzed and based on targeted net pay thickness the zone of interest are categorized as either having lower weak or strong stress barriers. Stress profiles derived from dipole sonic logs that runs across both the zone of interest and in shales (below and above the net pay) are calibrated with stress values from Mini Falloff Test (MFO) from offset wells. In addition, net pressure & leak-off properties are also calibrated. A Fully-3D modeling fracturing software was utilized to design the artificial barrier treatment using both slick water and hybrid fluid treatments and varying proppant volumes in order to simulate frac height growth with the aim of ensuring minimal or no contact with underlying water zones. Wells landed in different sand bodies sizes were considered and categorized under crest and core section of the field. Wells drilled in the crest section displays narrower, shorter pay zones and falls under the higher risk due to its proximity to the aquifers, while wells drilled in the core section of the field falls into the lower risk of communication with the water bodies due to its thickness. Generated height growth from frac simulations are analyzed for both slick water & hybrid frac treatment designs with varying amounts of proppant volumes. Simulated frac geometry were evaluated and the desired treatment types for both cases were selected based on the risk category. The preferential treatment type for the higher risk crest section of the field are slick-water and hybrid treatments respectively. Presence of adequate and inadequate stress barrier and the availability of decent net pressure based on MFO test were considered during the selection process. Estimated fracture height growth derived from post-frac evaluation pressure matches and production history matches were evaluated and results show adequate containment above undesired wet zone. In addition, offset well production comparison were performed which shows lower WGR during the initial productions for both wells as compared to existing offset wells that were treated with cross-linked fluid system. This paper introduces the stimulation design utilized to mitigate and minimize interaction with aquifers of zone of interest. The paper provides validation process to demonstrate how effective the artificial mitigation process can be irrespective of the proximity of the treated zones are to the underlying water zone. The validation process was performed after the mitigation treatment is pumped to evaluate the treatment. Recommendations for the design of future fracture treatments with close proximity to underlying water can be made based on sand bodies risk categories in which the well is landed. With adequate petro-physical log, mechanical information, and offset well data, treatment fluid type selection can be made based on desired fracture height growth. The knowledge gained with this study can be utilized to dealing with designs that involves proppant stimulation near water beds with inadequate stress barriers.