The nature of tight gas reservoir consists of heterogeneous sub-units separated by impermeable denses and various depletion level has become the greatest challenge on how to exploit this typical reservoir at its maximum. Despite maximum reservoir contact is the best method to deliver the highest well production, this paper tries to tell another success story about UBCTD applied in a triple lateral well which can deliver greater productivity than a normal overbalanced multilateral well. The study methodology begins with the evaluation of the current remaining potential sweetspots throughout the reservoir. The assisted history matching is used to generate 3 different model realizations: Low - Mid - High case that can map-out sweetspot distribution called Simulation Opportunity Index (SOI) map. SOI integrates 3 independent components selected from static and dynamic parameters: reservoir permeability-thickness, movable gas and reservoir pressure from a historically-matched dynamic model. One particular area is then selected and evaluated furthermore for the final new well and trajectory placement. The well was drilled as a triple lateral with one of the lateral was fully placed in prime sub-unit that likely holds the potential remaining sweetspot in the area according to SOI method with expectation to maximize its recovery. During the drilling, UBCTD technique was implemented because it offers several advantages such as reduction of formation damage, reduction of drilling fluid loss into formation, avoiding losses-related drilling problems and risk of differential sticking and creating cost saving for completion and stimulation requirements. Earlier study in the field signified that generally, the well productivity is strongly influenced by the type of the lateral and the geological structure. For instance, the triple lateral well located at higher structure normally gives higher productivity than the triple lateral well located underneath it. Theoretically, higher productivity will be given by the triple lateral compared to the situation if the same area is developed by dual lateral or even by the single lateral well. Currently, the implementation of UBCTD in this triple lateral well was confirmed to provide better productivity up to double exceeding a conventional overbalanced with the same well laterals. Greater initial gas production rate with high THP was evidenced during the well clean-up. UBCTD application in tight gas reservoirs is not only aimed to improve the initial well productivity significantly beyond the conventional overbalanced well but it is also expected to create more equal pressure drawdown distribution along the lateral drain because of many given advantages as stated above. At last, cost saving can be performed because the operating cost which is usually spent on normal wells for well stimulation can be reduced.

The giant onshore gas field in this study consists of six stacked reservoirs and has been producing for over three decades. The field has more than 150 gas producing wells and has several wells which have low-intermittent gas production rates. The low production is attributed to weak wells sharing common trunk lines with prolific wells. This study investigates the impact of choke optimization, surface network reconfiguration and wellhead compression to improve the gas production from weak wells after performing detailed analysis of possible root causes from the surface network by using an Integrated Asset Model (IAM) as the digital twin of the field. The investigation begins by identifying weak producers and involves studying the integrated surface network and determining the root causes for backflow and unstable hydraulics. After surface network issues have been recognized, remedial modification will be implemented. The impact of different choke settings on the wells are studied. The final step will be to introduce wellhead compressors on the weak producers. Extensive sensitivity scenarios are performed to identify the optimum compressor inlet pressure for each individual wellhead compressors and the wells which benefit most from the application of wellhead compressors are ranked. The multi-reservoir gas field contains six stacked reservoirs which are producing under depletion mode and share a common surface network. Root causes of weak or shut-in wells due to backflow or hydraulic issues are successfully identified by using an IAM simulation tool. The investigated remediations were simple optimization of the choke settings, reconfiguration of the surface network, and application of wellhead compressors to improve the gas production from the problematic wells. It is observed that the addition of wellhead compressors resulted in the most significant increase and more sustainable production from the weaker wells. Furthermore, the final selection of candidate wells for wellhead compressors can be dictated according to the highest gain from the ranking. The study revealed that the implementation of wellhead compressors will significantly increase the cumulative gas production from the selected wells at the end of field life and will result in positive production acceleration from the field perspective. This study shows that adding wellhead compressors to weak producers can mitigate the production bottlenecks and backflow issues and that higher and more sustainable gas production can be achieved from the weak wells after understanding the primary causes for low/intermittent production from the IAM which is acting as the digital twin of the field.

Despite intelligent method such as numerical simulation model has been used, identifying areas or zones that still holding high potential of production still becomes the most challenging aspect in the development of mature carbonate oil field with high water-cut; especially coupled with the lack of required important data to generate such appropriate model. A practical method to explore the sweet-spot areas within the field is then introduced, hereinafter called "Simulation Opportunity Index" (SOI) based on techniques already established in the industry. SOI is an integration of three (3) independent components whereas each of them is normalized to produce indexes that represent reservoir-permeability thickness, movable oil and reservoir pressure from a historically-matched dynamic model. The method utilizes the historically-matched simulation model in which the water saturation from the dynamic model is calibrated with the recent acquired cased-hole logging saturation log to improve the confidence level. The cased-hole logging saturation log results are treated as the only ground truth of the current saturation within the reservoir thus it plays important role to reduce the model uncertainty and to simplify the workflow in efficiently short time. The SOI method is hence used as an invaluable tool to spot areas for further development such as infill wells. The workflow to produce the potential areas within the reservoirs is discussed in this paper including comparison to see infill wells performance by using both conventional and SOI approaches. Notwithstanding lesser producible oil reserves due to denser-placed infill wells over time and high water-cut of the field >95%, the method after implementation in numerical simulation is capable to screen-out a number of sweet-spot areas for infill wells placement in the largest mature oil field of RH PetroGas (Basin) Ltd concession in Salawati basin, onshore West Papua, which can be ranked thereupon for execution after sensitivities and economics analysis. The infill wells are still the most technically-favourable development scheme to hold oil production decline about 6%/year in the field. Thus, it is essential to place the infill wells within the most optimum locations that would yield maximum sweep efficiency, acceleration of the expected recovery or incremental increase of the Estimated Ultimate Recovery (EUR) from such heterogeneous reservoirs. The application of SOI methodology in numerical model is helpful to practically identify areas or zones with high oil potential due to non-uniformity volumetric sweeping efficiency in carbonate reservoirs in relation to their tremendous heterogeneity, variable wettability and dual pore network.

Due to the declining reservoir pressures in some of its onshore gas carbonate fields, ADNOC decided upon an initial 3 well UBCTD, (Underbalanced Coil Tubing Drilling), campaign in its onshore Asab and Bab fields, with 2 wells to be drilled in Asab and 1 in Bab. Both target fields have high H2S concentrations up to 6% and ADNOC undertook the necessary candidate selection process, Basis of Design, and equipment selection to enable them to drill these wells using UBCTD techniques. Due to the high H2S content, it was required that a closed loop system design was implemented, which was the 1st successful one implemented in the Middle East. The project's given objectives were analyzed, and the planning was conducted considering the different aspects to achieve ADNOC's objectives and expectations. Several challenges were faced during the designing phase which had to be resolved prior the operations start-up. These challenges included extended drilling reach, closed loop returns handling system, handling high H2S levels at surface amongst others. One of the main design objectives, the drilling reach, was improved by optimizing the trajectories Dog Leg Severity, (DLS), and Bottom Hole Assembly, (BHA), configuration. Instead of a conventional mud motor, a turbine was used to give power to the bit and allowed having a lower Weight on Bit, (WOB), to drill the formation, thereby increasing the depth of the section. The trajectory was planned in a way to maximize the reservoir contact within the production layers and reduce footage in the non-productive zones between the producing formations, therefore maximizing the well productivity. Increasing the well production was key to the project economics and to prove the value brought by the UBCTD to ADNOC's hydrocarbons production. Several business disciplines collaborated closely under the IWC, (Integrated Well Construction), stewardship to provide practical solutions and design a system specifically tailored to achieve the objectives and overcome the various challenges associated with this project. The final solution was a closed loop system capable of:removing solids/drilled cuttings from the system.measuring flow rates of different fluid phases (gas, condensate & water).treating and removing H2S.exporting gas and condensate to ADNOC's production facility.whilst drilling the well in Underbalanced conditions. After the operations start-up on the 1st well, the returns handling system was modified to improve the efficiency and enhance the safety of the personnel and equipment. This paper will discuss the design and planning involved in the successful drilling of these three wells and the operational challenges and mitigations encountered while drilling.

An onshore retrograde gas field in Abu Dhabi has several wells with severe liquid loading issue as reflected by low intermittent production rates. To overcome this, a study was performed by looking at the effectiveness of downhole and wellhead compression and their impact on the production rates. Utilizing IAM, the benefit will not only be seen at the well level but also at the field scale with the ultimate goal to increase the Recovery Factor. The study was started by identifying the wells suffering from liquid loading issue. The wells were then ranked according to the severity of the problem based on the GLR values. Hence, the top 2 wells were prioritized as the candidates. Both the downhole and wellhead compressors were then modelled in IAM and several sensitivity runs were performed to evaluate the optimum compressor settings to see the impact on flow stabilization and wells productivity. The selected best scenarios were also compared with the base case as reference where no intervention was performed at all (natural flow). The study reveals that both downhole and wellhead compression can give wells flowrate stability with substantial improvement on the production rates for longer duration of time compared to the base case scenario. More than that, the downhole compression shows better gain for production rates compared to the wellhead compression. This is mainly attributed to the fact that gas density is higher at the bottom of the well than at the surface and since the mass flow rate depends on the density of the gas and the volumetric flow rate, this will lead to higher mass flow rate for the same volumetric flow. Consequently, a downhole compressor will produce more fluid quantity rather than a wellhead compressor. The study clearly demonstrates and evaluates the effectiveness of downhole and wellhead compressors to mitigate liquid loading inclusively to improve gas wells production. By utilizing IAM that is capable to capture the interactions between subsurface to surface network elements, the improvements on wells deliverability after implementing downhole and/or wellhead compression can be accounted more accurately taking into account more complex production operations with the ultimate goal to maximize the field Recovery Factor.