Originally, an infill well from project H was approved in 2013 to be completed as a single zone Open Hole Gravel Pack (OHGP) to produce gas commingled from three sands located at the shallowest reservoir in that field. Interpretation of recent logs from a nearby producing well indicated that there was significant water threat at two of the sands which would lead to water influx from the beginning of production if the well was to be completed as a single zone OHGP.
The well was then redesigned to be completed as a Cased Hole Gravel Pack (CHGP) in order to have mechanical isolation from the water zones with an inner string and internal isolation packers to allow feasibility of zonal isolation to shut off the water producing zone in the future. This feature however resulted in higher well cost as compared to the approved design.
Due to recent hostile low oil price, a more cost-effective sand control design was evaluated to reduce the well cost while maintaining similar performances as a CHGP design in terms of the capability to delay water breakthrough. Design feasibility study was performed on multizone OHGP with open hole mechanical packer and an inner string design to evaluate its performance and magnitude of cost reduction relative to a CHGP design.
Skin analysis was performed for both OHGP and CHGP completion designs to evaluate any additional pressure loss for each sand. Prior to compartment optimization, an OHGP completion without packer placement was simulated in a dynamic simulation to generate the production profile as a base case. This was followed by a compartment optimization that was performed with OH mechanical packer placement at various standoff distances from the Gas-Water Contact (GWC) such as 5ft, 10ft, 15ft, 20ft and 30ft respectively.
Subsequently, similar analysis was then performed on the CHGP completion design with a higher skin value estimated for the CHGP completion to reflect a higher degree of damage resulting from the cementing and perforation operations. Several production sensitivities were simulated by varying the perforation length and standoff from the GWC to replicate the same scenario of the open hole mechanical packer placement in the OHGP design analysis. Finally, analysis on the effectiveness of the base case (OHGP with no packer) against the cases of OHGP with optimum packer placement and CHGP with optimum perforation depth were compared and ranked over cumulative gas production, cumulative water production, operational complexity, and risk as well as total well cost.
Based on the dynamic modelling, the base case (OHGP without packer) showed water breakthrough occurring right at the start of production as expected. Once breakthrough occured, water production would rapidly dominate production. On the other hand, packer placement sensitivity analysis for the OHGP design showed that the optimum depth for packer placement was 20ft or 30ft above the GWC depth where it provided highest gas cumulative and lowest water cumulative production throughout the well life. With offset distance of at least 20ft away from the GWC, the cumulative gas production for the OHGP and the CHGP cases were found to be similar and the cumulative water production for the OHGP case was slightly lower than the CHGP case.
Mechanical open hole packer was recommended instead of swell packer after considering the risk of inadequate isolation by swellable packer that would lead to early water breakthrough which would subsequently reduce the cumulative gas production. As a result, an OHGP with open hole mechanical packer and inner string was selected to be the most optimum design for this well with estimated cost reduction of nearly 13% from a CHGP design. In general, an OHGP with OH mechanical packer at 20ft or 30ft standoff from the GWC brought benefit to the infill well in terms of cumulative gas production gain and low water production while eliminating sand production.