Over the last few years, ADNOC has systematically investigated a new polymer-based EOR scheme to improve sweep efficiency in high temperature and high salinity (HTHS) carbonate reservoirs in Abu Dhabi (Masalmeh et al., 2014). Consequently, ADNOC has developed a thorough de-risking program for the new EOR concept in these carbonate reservoirs. The de-risking program includes extensive laboratory experimental studies and field injectivity tests to ensure that the selected polymer can be propagated in the target reservoirs. A new polymer with high 2-acrylamido-tertiary-butyl sulfonic acid (ATBS) content was identified, based on extensive laboratory studies (Masalmeh, et al., 2019, Dupuis, et al., 2017, Jouenne 2020), and an initial polymer injectivity test (PIT) was conducted in 2019 at 250°F and salinity >200,000 ppm, with low H2S content (Rachapudi, et al., 2020, Leon and Masalmeh, 2021). The next step for ADNOC was to extend polymer application to harsher field conditions, including higher H2S content. Accordingly, a PIT was designed in preparation for a multi-well pilot This paper presents ADNOC's follow-up PIT, which expands the envelope of polymer flooding to dissolve H2S concentrations of 20 - 40 ppm to confirm injectivity at representative field conditions and in situ polymer performance. The PIT was executed over five months, from February 2021 to July 2021, followed by a chase water flood that will run until December 2021. A total of 108,392 barrels of polymer solution were successfully injected during the PIT. The extensive dataset acquired was used to assess injectivity and in-depth mobility reduction associated with the new polymer. Preliminary results from the PIT suggest that all key performance indicators have been achieved, with a predictable viscosity yield and good injectivity at target rates, consistent with the laboratory data. The use of a down-hole shut-in tool (DHSIT) to acquire pressure fall-off (PFO) data clarified the near-wellbore behaviour of the polymer and allowed optimisation of the PIT programme. This paper assesses the importance of water quality on polymer solution preparation and injection performance and reviews operational data acquired during the testing period. Polymer properties determined during the PIT will be used to optimise field and sector models and will facilitate the evaluation of polymer EOR in other giant, heterogeneous carbonate reservoirs, leading to improved recovery in ADNOC and Middle East reservoirs.

The key objective of the CO2 WAG Pilots is to confirm improved sweep and to enhance oil recovery under CO2 WAG relative to water flooding. Two CO2 WAG Pilots are in progress in a giant Abu Dhabi Oil Reservoir. Each pilot has one horizontal producer and two horizontal injectors along with two vertical pilot observers. A detailed monitoring plan was designed and implemented to monitor pilots’ performance and track CO2 breakthrough and flow path. Injectivity of both water and CO2 was determined in the WAG cycles to investigate any loss of injectivity. The producers are being tested daily for oil rate, water cut, GOR using multi-phase flow parameters (MPFM) while portable test separators are used every quarter to validate these measurements. PVT analysis of produced fluids are being carried out on samples from portable test separators and MPFM sampling point to monitor CO2 content. Different gas and water tracers have been injected to trace the movement and breakthrough of injected fluids into the pilot producers. Carbon and oxygen-isotope analysis for produced and injected CO2 gas is also carried out to monitor CO2 breakthrough. RST logs in the observers demonstrate good sweep across different layers of the reservoir and show that WAG is providing mobility control to CO2. Several data sources were analyzed to determine CO2 breakthrough time and the CO2 flow path. Analysis of CO2 in produced gas has determined the timing of CO2 breakthrough. This is supported by the isotopic analysis of injected and produced CO2 in pilot producers and near-by producers. The tracer analysis results unambiguously identify the source of the produced CO2. Injectivity analysis of both CO2 and water showed injectivity of CO2 was either the same or higher than water injectivity. Moreover, no loss of injectivity was observed between WAG cycles. The pilot has been operated successfully without HSE issues since 2016. Corrosion logs are acquired within the extensive monitoring program along with inhibitor injection to avoid any Asphalting deposition. The paper discusses the performance of the first multi-well CO2-WAG pilots in a giant onshore reservoir in Abu Dhabi which is used to de-risk multiple CO2 WAG full field projects in ADNOC reservoirs. It also highlights the importance of the different reservoir monitoring tools for improved understanding of the pilots which will be used as a basis for implementing CO2 WAG for the full area development.

Water production normally increases as field gets more matured; especially for fields developed via water injection or natural aquifer support. Handling water production is always a challenge from both financial and environmental prospects. The field under study is a giant oil and gas producer in Gulf area. Before embarking on the PWRI project, the routine way to handle the field's water production (~65 Mbbls/d) was to dispose through dedicated wells drilled only for that purpose and completed as open hole in Dammam, Simsima and UER formations. On the other hand, the water injection project sourced by water supply wells drilled and completed with ESP's through the same formations.In 2010, PWRI project was commenced through replacing the aquifer water injection by produced water re-injection in one of the water injection clusters without water treatment. Since then, about 22-29 Mbbls/d of produced water are being injected through four water injection wells. After commencing the project, it was very crucial to assure that, no injectivity impairment due to produced water re-injection in addition to wells' integrity.The water injection performance was closely monitored as WHIP and injection rate and using some techniques like Hall plot to detect any injectivity impact. Pressure fall-off tests (PFO) were frequently performed to detect any formation damage associated with PWRI. Moreover, PLT was performed in one of the wells before and after switching from aquifer water to injection water. The two logs were compared and proved that, there is no change in the injection profile across the horizontal section of that well. Corrosion logs were also utilized showing that, no integrity issues related to PWRI. As of now, some 24 MMbbls of produced water were injected with no impact on wells' injectivity or integrity.

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One of the reservoirs in a giant field in onshore Abu Dhabi has been producing for six decades. The reservoir was already saturated at the time of production commencement, with a large oil rim and a gas cap. Both water injection and lean gas injection have been relied upon to sustain production, and will play an even more prominent role for the future development of oil rim and gas cap. Due to the stakeholders’ different entitlements / equity interests in the hydrocarbons originally existed in oil rim area versus gas cap area, it is important to be able to allocate liquid hydrocarbon production and injection gas utilization among the stakeholders, based on a systematic framework. This paper presents a comprehensive comparison of two modeling-based approaches of fluid tracking for condensate allocation and gas utilization – a tracer modeling option in a commercial reservoir simulator, and a full component fluid tracking approach implemented for this reservoir. The component tracking approach is based on the idea that if individual components represented in a fully compositional reservoir model are tracked separately starting from model initialization, one can trace back the source of hydrocarbon production from both gas cap and oil rim. This approach is implemented through the doubling of the number of components in the equation of state fluid characterization – one set of components for the gas cap, and another set for the oil rim. In order to track the net utilization of the injected lean gas, additional components are needed – in this case one more component representing the lean gas, as the injected gas is a dry gas. The results of the comprehensive comparison demonstrate very clearly that these two approaches yield consistent condensate allocation and gas utilization results over the entire life of field (including history match and prediction). For condensate allocation, the hydrocarbon liquid production split depends on how the injected lean gas is tracked. For gas utilization, the injected lean gas must be tracked as a distinct component separate from both oil rim and gas cap components. The comparison also shows that although the tracer-based approach is numerically more efficient with less runtime, the full component tracking approach is simulator agnostic, and therefore can be implemented in any reservoir simulator. In addition, the full component tracking method can be used for cases where injection gas is a known mixture of oil rim and gas cap gas – something the tracer-based option cannot handle. In summary, this paper presents a first comprehensive comparison of the two (2) different fluid tracking modeling approaches, with practical recommendations on modeling-based hydrocarbon liquid production and injection gas utilization allocation in cases where the commercial framework makes such allocation necessary.