Abstract
Hydraulic fracturing optimisation requires addressing numerous challenges including characterising geomechanical parameters and defining optimum perforation intervals for fracture initiation, proper selection of fracturing fluid and proppant, optimising fracture geometric parameters and injection schedule. This paper presents a case study of tight sand reservoirs with permeabilities as low as 4.2 milli Darcy (mD), interbedded with multiple shale layers in an oil field located in offshore Malaysia. Initial production tests showed low oil rates from tight sands and this study is aimed to assess the feasibility of economical production increase by means of hydraulic fracturing.
A geomechanical model was developed using petrophysical and well data including full-wave acoustic data, acoustic image logs and in-situ measurements of pore and fracture pressures. Rock mechanics test results were used to develop correlations between dynamic and static rocks elastic properties. These data were used to model poroelastic horizontal stresses for reservoir and bounding formations to assess the stress contrast (barrier). Breakouts and leak-off tests were used to verify the stress model. The results showed a modest least stress contrast between the upper sands and interlayered shales, allowing a propped fracture containment within the pay zone of upper reservoir. However, a higher stress contrast between the lower reservoir and bounding shales posed a challenge to achieve a desired fracture confinement.
Analysis showed that the oil rate increased proportionately with fracture half-length up to 300 feet (ft) and conductivity up to 3500 milli Darcy-feet (mD-ft), above which the production benefit diminished. Optimum perforation interval was selected in the middle of pay zone to achieve the desired fracture geometry, conductivity and confinement. An injection schedule was designed to use ceramic proppants and a cross-linked fracturing fluid to achieve the optimum fracture length and conductivity, efficient proppant concentration and transport, and fracture containment. With the proposed fracture stimulation schedule, average productivity is expected to increase up to five folds compared to an un-fractured well. For the upper reservoir, which has a relatively low permeability, cumulative production after fracturing treatment will continue to increase up to three years after which, the production rate will decline to a non-fractured reservoir. The results of this study are used to evaluate the economical well stimulation and to address the completion challenges of two planned pilot wells shortlisted for hydraulic fracturing.
