Managing adequately pressure drawdown should be a key technical reservoir management driver due to its major impact on cash flow, acceleration and final recovery factor for operating hydraulically fracture shale gas condensate producers. Permeability should be regarded as a key dynamic property for ultra-low permeability shale reservoirs that influences shale hydrocarbon recovery. It is paramount to develop a pressure depletion plan that captures the pressure drawdown strategy and the changes in flow capacity associated to the interaction of the nano-Darcy rock and hydraulic fractures with stress dependent permeability effects.
Defining the adequate drawdown strategy would aid maximizing the economic recovery. Considering the variability of permeability with pressure drawdown should be part of the reservoir management lifecycle for unconventional shale reservoirs. This study focus on evaluating the impact of pressure drawdown strategy on initial rates and recovery for a Duvernay Gas condensate producer with an initial condensate yield of 100-150 stb/mmscf.
A sector compositional reservoir simulation model was built for a horizontal multistage hydraulically fracture Duvernay shale gas condensate producer. A full assessment of variability of permeability in the nano-Darcy rock and in the propped hydraulic fracture stages near the wellbore region was accomplished. Aggressive, moderate and conservative pressure drawdown strategies were evaluated, considering multiple operational pressure drawdown incremental ranges from 14.5 to 95 psia per day.
Results clearly indicate that implementing daily pressure drawdown increments of 22 to 29 psia per day would provide a similar recovery factor than imposing daily pressure drawdowns of 44 to 95 psia per day. However, there is a golden operating window opportunity to accelerate recovery by imposing maximum drawdown from the early days of production and bringing significant benefits of accelerating recovery with an associate increase in revenue but the benefits of this acceleration vanished in less than one year due to substantial changes in hydraulic fracture conductivity and also in the nano-Darcy rock permeability in the near wellbore region. The reduction of nano-Darcy permeability is a function of pressure, time and distance from the hydraulic fractures. According to our results, the best reservoir management practice for operating lean/medium Gas Condensate unconventional shale producers should be maximizing pressure drawdown at the early stage of the life cycle and deferring the installation of production string to maximize inflow-outflow.
This paper presents how streamline technology in combination with conventional water injection management indicators was used to effectively manage water injection in a giant field. Describing the relationship between injectors and producers is obtained from a streamline simulation model. Adjusting injection requirements only, based on well streamline injection efficiencies, is not possible for all regions of the reservoir since a good history-match is not always achieved in all regions, particularly for a giant simulation model with 520 producers and 160 injectors. Thus, conventional water injection management indicators like injection/production ratio(IPR) target per segment, reservoir pressure distribution and maximum water injection plant facilities should be taken into consideration to distribute the water efficiently.
The new proposed methodology, through an iterative process, links the streamline simulation results to the practical aspects of conventional peripheral water injection management considering water injection facilities constraints and routine reservoir performance metrics. The new approach improves injection efficiency for all segments simultaneously in a single run. We have accounted for redistributing water injection among several segments connected to a single/multiple water injection plants (WIPs). Results indicated that a similar oil production rate can be obtained through optimization. The main benefit is that water injection is managed more effectively with the excess amount of water not injected in a particular month or quarter, could be transferred and injected into other fields.