As a result of Reservoir Monitoring Plan, a Non-uniform Saturation has been identified in the Southern part of the reservoir. High gas saturation, coming from gas injection in underlying units, was observed within the first 10 to 30 Ft. TVD of top-most section of the reservoir. Therefore, in order to mitigate the potential problems that this gas production can generate on the well production performance which could shorten the well productive life, a flow control strategy was implemented in the lower completion designs of six new drilled wells. Following the best practices as per ADNOC Standard Operating Procedure and after performing an opportunities screening, inflow control device ‘ICD’ was found as the technology to be used on these cases. A steady state modelling was performed for identifying the most suitable ICD design for the new wells drilled during 2021-2022. In order to consider the changes on the reservoir fluid conditions over time along the wellbore, a sensitivity analysis was conducted during the steady state modelling. Likewise, the final ICD design took into account that production profile should be adhered to reservoir management guidelines. The result of wellbore simulations provided insights about the optimum solution for the well completion. This called for both adequate well positioning along the reservoir section and the utilization of ICD technologies as a means for GOR control, making feasible a more efficient practice for well and reservoir management. A successful trial of installing the first Autonomous or self-regulating ICDs have been completed and deployed as an innovation in the field to optimize and balance downhole influx profile, which will allow to minimize the impact of the gas breakthrough GBT while maintaining wells productivity. Overdesigned ICDs was avoided since they not just increase the cost of well completion, but also will impact the well performance negatively. Most of wells with segmented completion with Autonomous Inflow control Device AICD pertaining to PAD drilling project, will be commissioning in Q2 2023. One out of the six wells is currently flowing and an evaluation program and results will be further discussed in this publication.

This paper covers a super giant carbonate oilfield in the Middle East that has enjoyed pressure support and voidage maintenance, primarily with peripheral water injection and pattern development in some reservoir units over the last decades. However, premature and non-uniform water front advancement has been a great challenge, resulting in early and uncontrolled water breakthrough with some wells becoming inactive due to increasing watercut. This challenge is mostly attributed to reservoir heterogeneity and particularly to the presence of un-mapped high permeability streaks (greater than 1Darcy) in the carbonate reservoir, usually resulting in by-passed oil and high value of Remaning Oil Saturation with poorer sweep efficiency. As a result, aiming to reach the desired ultimate recovery factor has become a challenge. A multidisciplinary approach involving the integration of various datasets, including geology (core facies and core description), geophysics (seismic stratigraphy), petrophysics (open hole logs, cased hole saturation time-lapse logs, and cased hole production logs), reservoir and production engineering (actual wells performance), and drilling data (mud losses, pilot hole) etc, were used to identify the high permeability streaks aerially and vertically within the reservoir. These high permeability streaks were then tested in the 3D dynamic model with various sensitivities to assess the impact on the reservoir performance in order to improve the match with the actual performance. The preliminary results were further validated by acquiring more data and gaining deeper understanding from Pulse Neutron logs, Injection and Production Logging, Flow tests, Pressure Transient Analysis etc. In order to reactivate inactive wells, increase production performance, and improve the sweep efficiency, targeted water shut-off was carried out to isolate the watered out intervals. Injection and Production logging gave more insights to understanding injection conformance and reservoir performance with adequate measures taken to ensure optimal reservoir management. In addition, areas with by-passed oil were targeted with revised well completion, infill drilling and artificial lift strategies. This paper describes the approach used, challenges encountered, results obtained, and the way forward.

Reservoir monitoring carried out using previous-generation pulsed neutron logging tools worked well in ideal borehole conditions. However, evaluations were complicated in non-ideal borehole environments, such as gas in the borehole, which affects capture cross section, sigma, and thermal neutron porosity measurements, changing borehole fluid holdup, which confuses carbon-oxygen interpretation, and identifying hydrocarbon type using only neutron porosity when oil density and hydrogen index are very low or open hole (OH) data are unavailable. A new-generation pulsed neutron logging tool has been introduced that benefits from a high output neutron generator, two LaBr3 detectors, one yttrium aluminum perovskite (YAP) detector, one neutron source monitor, and an improved acquisition sequence. It provides self-compensated measurements of sigma and thermal neutron porosity, along with full capture and inelastic spectroscopy, including total organic carbon (TOC) and carbon-oxygen ratios. This tool also measures a new formation property called the fast neutron cross section (FNXS), which provides a gas saturation estimate independent of conventional methods. All measurements are recorded in the same logging pass, thus reducing overall logging operation time. Pulsed neutron measurements were acquired in lateral wells using the new generation tool in the A field, onshore Abu Dhabi. Through lateral sections with changing oil, water, and gas holdups in the borehole, and in changing completion environments, robust sigma and neutron porosity measurements were acquired with the help of the automatic self-compensation algorithm. Neutron porosity helped quantify gas saturations where the OH data are available and of good quality. However, in zones where it is not possible to use the neutron porosity by itself (for example, in zones with missing or uncertain OH results), the FNXS measurement provided an independent estimate of gas presence and saturation. FNXS of brine (7.5 1/m), calcite (7.5), and oil (6.0 to 7.0), are similar and strongly contrast with the FNXS of gas (1.5 to 2.5). Thus, the measurement is insensitive to porosity by itself but highly sensitive to gas presence. A crossplot of thermal neutron porosity (TPHI) and FNXS provides a robust estimate of gas saturation in wells where OH results are uncertain or not available. This paper presents, through multiple examples, a first comprehensive look at the various challenges faced while logging lateral wells in a light oil environment and showcases how a combination of self-compensated measurements coupled with the new measurement of FNXS can make data interpretation more robust in complex borehole and completion environments.

The development of Lower Cretaceous reservoirs in a mature field located 84 km southwest of Abu Dhabi required a series of stress measurements across the reservoirs to tectonically calibrate the 3D Geomechanical model. The stress measurements were acquired by multiple straddle packer microfrac tests conducted through pipe-conveyance in a slim openhole wellbore. Various pore pressure depletion conditions across the reservoirs make the deployment of straddle packer tools in slimholes a very challenging operation. Five in-situ stress measurements are acquired in this study from the proper identification of fracture closure pressure after reaching the formation breakdown pressure. Each microfrac test consists of three pressurization cycles and three pressure decline (fall-off) periods after fracture propagation. The fracture closure identification is achieved using three different pressure decline analysis methods on each fall-off test: (i) square-root of time, (ii) G-function and (iii) Log-Log plot. The final fracture closure measurement is obtained after consolidating the three fracture closure identification results in all three injection cycles conducted on each microfrac station. The Microfrac tests conducted in the vertical pilot borehole provide precise in-situ measurements of formation breakdown, fracture reopening, propagation and closure at multiple reservoir layers. These in-situ measurements provide an accurate present-day stress profile across the reservoirs for constructing a proper 3D geomechanical model of the field. These microfrac tests measure minimum horizontal stress gradients of approximately 0.66 to 0.76 psi/ft, confirming the normal faulting stress regime in these reservoirs. The tectonic stress calibration is obtained by adjusting the value of tectonic strains across the reservoirs until the log-derived minimum horizontal stress matches the fracture closure pressure from the microfrac tests. These in-situ stress measurements provide the subsurface information required to fully calibrate the tectonic stress acting on the reservoirs. This tectonic stress calibration is needed to create a representative 3D geomechanical subsurface model to predict accurate subsurface responses to stress and fluid flow over the field development. Additionally, conducting microfrac tests in slimholes provides multiple acquisition benefits: the straddle packer tool tolerates higher differential pressure across the elements than in large borehole, achieving higher absolute bottom hole pressure to induce formation breakdown; the borehole induced stress zone is radially smaller compared to larger hole sizes; the induced fracture does not required excessive propagation away from the borehole in order to capture the far-field in-situ closure stress.

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.