An integrated asset model (IAM) was constructed for an onshore carbonate gas condensate asset in Abu Dhabi. The strategic priority of the field is to optimize recovery of liquids and, therefore, the field is operated under gas recycling. After processing, dry gas is reinjected for the purpose of maintaining reservoir pressure to maximize condensate recovery. However, gas is a critical natural resource, and so a strategic decision was taken in 2011 to assign a portion of the produced gas for sales and use nitrogen as a makeup fluid to maintain reservoir voidage. The long-term implications of this decision will be the need for installation of nitrogen rejection units to ensure produced gas meets sales specifications after the field blows down. The IAM brought together reservoir, well, pipeline, and facilities domain models into an integration platform that provides an increased level of modeling fidelity by removing some of the simplifying assumptions and enabling cross-discipline collaboration to achieve understanding of the asset's problems and objectives. The model itself is complex and comprises a multimillion-cell reservoir simulation model, production and injection pipeline models, and a simplified model of the gas processing facility, all of which utilize a fully compositional approach to fluid modeling. The model was validated over a period of 6 months of production history by comparing calculated rates and pressures with measured field data from the field at the facility, trunkline, and well level. Once the validation phase was completed, the IAM was used to predict life of field performance. The IAM approach provided critical information not available from traditional standalone modeling. Firstly, more accurate accounting for the backpressure impact on the production and injection wells resulted in significant differences in production and injection profiles. Secondly, the inclusion of a facility model to update the injection composition resulted in major differences in nitrogen production. Finally, as a result of collaboration with facilities production, operations, and facilities teams during the project, the historical match to condensate production was considerably improved.

This paper presents a feasibility study for the development of the unexploited outlying area of a gas condensate field operating under gas recycling mode to optimize condensate recovery. Heavier components have migrated to the flanks which is the motivation to exploit this area. To maintain reservoir pressure the voidage replacement ratio must be maintained at 100%. However, due to high demand for natural gas, a certain percentage is replaced with non-hydrocarbon makeup gas. This strategy has the potential to reduce the condensate recovery as well as affect the quality of the produced gas.A reservoir simulation study was conducted to maximize the condensate and clean gas recovery through development of the flanks. Two major scenarios were created consisting of more than twenty different development strategies based on well location, number of wells and well production rates. Additional sensitivities on blow down time, under-injection, injection stream composition and compression were considered for both scenarios. The influence of the surface infrastructure on production performance has been quantified by the application of Integrated Asset Modeling, which improves the accuracy of the standalone reservoir simulation scenarios.The study highlighted a significant upside in terms of oil recovery by exploiting the outlying area of the field. Multiple optimization scenarios were performed and a maximum gain of approximately 10% in recovery was observed above the base case. Integrated Asset Modeling led to more optimistic estimates of future recovery and reduced makeup gas production, through the removal of simplifying assumptions related to back pressure and injection composition.

Carbonate Reservoirs are well known for their heterogeneity in terms of porosity and permeability. In this field case from UAE onshore a sharp degradation of petrophysical quality was noted at the gas-water contact, in relation to diagenetic cementation, and led to an independent modelling for the aquifer, as well as an independent modelling of the reservoir with a data filter for the gas pool only. A merge of the 2 grids was then performed. In this field a major bias on well data distribution from crest to aquifer affects the geostatistical histogram evaluation: wells are concentrated in the crest down to mid-flanks while there are few wells from mid-flanks to the aquifer. Consequently distribution histograms of petrophysical data from the whole model should not respect well data histograms (whether, core-, log- or cell-derived). The methodology of separating gas and aquifer modelling, and of separating well derived histograms from model-derived ones led to the following results: – Better capture of the reservoir degradation with depth in the gas pool, – Better capture of the sharp degradation break in the aquifer. This paper is focusing on the methodology of how to build two separate models in the gas pool and the ‘aquifer for each petrophysical property and how to combine them in one property model to honour reservoir heterogeneity. Integration of all data at all scales and constant QC between database sources (logs, cores, seismic, dynamic history) were the means to produce a geomodel capturing the key heterogeneities of the reservoir, those with major impact on fluid front migration during production.