In the quest to improve reservoir management and maximize oil recovery, it is imperative to explore solutions that ensure the optimum benefit to cost ratio. While it is renowned as a reliable drilling technique tackling operational problems such as reduced Non Productive Time (NPT) and eliminating induced damage resulting from conventional drilling practice, modern Under- Balanced Drilling (UBD) applications have seen significant advancement enabling efficient reservoir re-development. Following the promising results and significant learnings yielded from the UBD pilots executed in onshore Abu Dhabi oil fields, wider application of UBD was considered for productivity enhancement in tight reservoir units in addition to maximizing reservoir knowledge through inflow data analysis while drilling. Consequently, a UBD campaign commenced by drilling two wells (X1 and X2) located in a challenging multi-layered tight reservoir with complex heterogeneities, including vertical/lateral permeability contrast and presence of faults/fractures. Overbalanced drilling in these zones causes formation damage resulting in limited contributing intervals within long horizontal drains, affecting communication and conformance between injectors and producers. Conventional stimulation techniques have proved inefficient in restoring well productivity/injectivity. The wells were drilled in stepping down trajectory maximizing reservoir contact and homogenizing inflow per subunit, with the laterals planned to cross existing reservoir features in order to evaluate their impact on flow contribution. Real time flow data were interpreted using service providers proprietary tool of Rate Transient Reservoir Characterization (RTRC). Current state of art RTRC method uses a rate integral productivity index (RIPI) that filters instantaneous PI while drilling in order to enable simultaneous evaluation of flow features and proper geo-steering to optimize well targets. In addition, multi rate tests at the end of each section were analyzed to establish a permeability/PI profile followed by mini build ups – when necessary – to confirm the reservoir pressure. Lessons learnt from the first well enabled improvent in the operational aspects of UBD control on the subsequent well through adequate design of UBD tools and conditions. RTRC analysis showed that the two wells were dominantly matrix producers with the well X2 indicated the presence of a secondary permeability attributed to fractures, which resulted in a higher well potential than expected. The acquired productivity baseline per sub layer will be useful in optimizing the completion strategy, considering smart completions and enhanced reservoir contact per sub layer. As a way forward, extending UBD application to other areas of the reservoir is also considered as an opportunity for future development. The case study presented herein, highlights the outcomes of RTRC in deploying strategic re-development options to improve reservoir performance and deliverability in the long term.

The Mississippian-age Meramec Series is one of the primary producing intervals of the Sooner Trend in the Anadarko Basin of Canadian and Kingfisher (STACK) counties, Oklahoma and is currently among the most sought-after hydrocarbon plays in the US. It is a low permeability and low porosity play; therefore, understanding reservoir limits, fluid characterization, and petrophysical characterization are critical to development planning of these reservoirs. In this study, we establish an integrated workflow for multi-component fluid characterization, stimulation-region limits and hydraulic-fracture-dimension estimation, and apply the workflow to a study area of the Meramec interval in the STACK play of Oklahoma. First, rate transient analysis (RTA) is used to characterize porosity, permeability, fracture dimensions and drainage areas. Subsequently, an Equation-of-State (EOS) model is established for the study area spanning the liquids-rich zone to high Gas-Oil Ratio (GOR) region. The EOS model is refined via compositional reservoir simulation by matching initial producing GORs field-wide and imposing compositional variations that would be observed due to thermal maturity. Reservoir parameters are then refined using the enhanced fluid model, and the integrated workflow is repeated until convergence. This approach has yielded an initial integrated fluid and petrophysical characterization and completion evaluation across an area of 1,000 mi2 within the STACK play. We have used production data from 2014 to 2017 for 20 wells in this area. A 15-component EOS model with 4 plus-fraction components is calibrated for the study area. Compositional gradients for methane and the first plus-fraction component are found to be 0.082 and 0.037 mole-fraction per 1,000 ft, respectively. Initial pressure gradient ranged within 0.42-0.65 psi/ft. GOR varied from 0.8 MSCF/STB in the liquids-rich zone to 1,500 MSCF/STB in gas zone. Formation volume factors of oil vary between 1.35-6.50 RB/STB. With regards to stimulated-region characterization, fracture half-length, fracture height, and drainage area ranged from 540-900 ft, 200-300 ft, and 315-505 acres, respectively. Integration of the various data allows for representative in-place volume estimates, as well as aiding in planning of optimal development and completion strategies.