In tight Cretaceous carbonates with complex reservoir and fluid typing, Nuclear Magnetic Resonance (NMR) petrophysical solutions has become a one of the integral logging technology to provide reliable and robust solution through systematic acquisition and processing methodology. This paper covers a case study from two carbonate fields of UAE applying innovative NMR log analysis techniques to understand varying complex reservoir porosities, permeabilities, identifying irreducible water, movable hydrocarbon and water in complex tectonic-cum-geological area, and identifying difficult gas-condensate fluid regime, validated by fluid sampling and testing to support optimizing well placement, and bringing confidence for fast track appraisal-cum-development program. The Nuclear Magnetic Resonance (NMR) Logs and its derivatives bring lots of value addition to overcome challenges in reservoir and fluid characterization for tight, complex and heterogeneous carbonate reservoirs. In the early life of exploration and fast appraisal stage of any carbonate field, measuring NMR log data for porosity typing (clay, capillary & free fluid), permeability variations, irreducible water saturation, identifying presence of movable water in unknown fluid contacts and resolving hydrocarbon typing through continuous T1T2 (simultaneous longitudinal relaxation-T1 & transverse relaxation-T2) with two dimensional (2D) fluid characterization to assist in differentiating condensate, gas, and water in reservoir static condition are such useful technical information coming out-off single logging tool to properly access reservoir and field potential. NMR data like porosity, rock matrix density and irreducible water saturation continuous profiling is already filling the gap for routine core analysis and capillary pressure data. These outputs from NMR can be easily integrated with other logs and geoscience data to plan perforation and testing in such challenging reservoirs. Despite NMR having shallower depth of investigation, with proper log acquisition plan, a good NMR data can be acquired and interpreted to get reliable interpretations for rock and fluid characterization, overcoming borehole and its fluid influences. Further all these NMR valuable data can be used for the application of reservoir rock typing in such complex carbonate reservoirs, if required. In today’s lower oil price and cost optimization phase, NMR logging is becoming popular acquisition tool providing most of time efficient petrophysical answers to reservoir and fluid characterization. The NMR log analysis products namely porosities (clay, capillary & free fluid), permeability, irreducible water, and fluid typing in difficult gas-condensate fluid regime validated by fluid sampling and testing has helped in trusting this systematic approach for fast track appraisal-cum-development program in these exploration-cum-fast appraisal carbonate fields. The NMR based log evaluation has been integrated with other logs and geoscience data to bring clarity on reservoir characterization, fluid typing and fluid contact to update the static model accordingly.

This paper covers a case study of successfully applying innovative NMR logging technology for fluid typing using continuous measurement from longitudinal and transverse relaxation two dimensional (2D) maps (2D T1T2app), helped in reducing fluid typing uncertainty in different clusters of one of the recent discovered gas-condensate Cretaceous stacked carbonate reservoirs of Abu Dhabi field. Generally, the reservoir fluid type in gas-condensate reservoir is confirmed by observing a representative fluid sample in laboratory, but at times collecting representative sample becomes challenging especially in tighter formations or unstable wells or rugose holes. The advanced logging techniques, such as Nuclear Magnetic Resonance (NMR) and Downhole Wireline Formation Testers (FT) with pump-out fluid sensors, can be extremely beneficial in resolving fluid types in downhole reservoir condition for such complex fluid regimes and is also applied in this recently discovered carbonate field. NMR continuous T1T2 (simultaneous longitudinal relaxation-T1 & transverse relaxation-T2) logging & 2D fluid characterization methods at closer interval have been very important and useful data to assist in differentiating condensate, gas, and water in each of the reservoir in the static condition. Free gas (methane) occupies a unique location in a 2D T1T2app map with a relatively long T1 and short T2 signature. Dead oils or low GOR oils typically have a low T1T2 ratio and condensates are identified by their fairly large T1T2 ratio. The fluid signatures from the 2D maps are then quantified to compute individual fluid volume for hydrocarbons and water. Reservoir fluid typing from NMR 2D T1T2app not only helped in optimizing formation tester PVT sample points, but was also found in agreement with fluid analysis results from formation tester sensors where reservoir fluids were sampled from a greater distance from wellbore after longer duration of pump-out period. The NMR Fluid typing using 2D-T1T2 app has helped identifying gas-condensate-water fluid types in static condition before sampling or testing. This has helped to understand regional fluid distribution in tighter reservoirs especially where fluid gradient has not helped due to unreliable formation pressure data. By applying NMR fluid typing in difficult gas-condensate fluid regime validated further by fluid sampling and testing, has provided confidence in placing perforation at correct depth for testing, improving regional fluid distribution and bringing timely value to optimize engineering techniques for fast track appraisal & development program.

Hydraulic fracturing is the industry-proven technology for efficient exploitation of tight reservoirs. This study evaluated the technology by drilling horizontal wells through acid fracturing the low permeability gas reservoirs of a lower cretaceous carbonate formation, located onshore Abu Dhabi. 1D Geomechanical modeling was critical in determining fracturing strategy. Containment of fracture height growth was the most critical aspect of the fracturing process, as the target units were stacked within heavily depleted reservoirs. The challenge was that the rock strength, poroelastic behavior and stress paths vary significantly through the various formations overlying/underlying to target reservoirs. In addition, the depositional nature of the target reservoirs meant inherent variations in rock mechanical properties. Hence, a continuous profile of in-situ stresses and other rock mechanical properties was essentially mandatory for addressing the challenges for optimal placement of the horizontal drain hole and assessing fracture height growth. Existing rock mechanical measurements, dipole sonic and image logs, as well as in-situ stress measurements were reviewed for 400ft (TVD) interval above and below the target reservoirs. Significant data gathering was managed in the vertical pilot hole of the first well to fill data gaps. A custom-built workflow was performed for 1D Geomechanical modeling in the first well, integrating poroelastic modelling with failure models. The study integrated drilling-induced and production-induced Geomechanical aspects into the 1D stress profile, including depletion-induced poroelasticity, shear anisotropy, and rock mechanical heterogeneity. Wellbore failures observed in vertical pilot hole and the in-situ stress measurements from offset wells were used for validating 1D Geomechanical model. This work resulted in a rigorous 1D-stress profile that contributed to initial fracture modelling, whilst de-risking the fracture height growth into the depleted reservoirs and optimizing the choice of drain hole location within sub-units of the target reservoirs. The fracture gradient and breakdown pressures derived from 1D stress profile were found to be in very close agreement with that measured from the minifrac conducted in vertical pilot hole of the first well. This paper presents a purpose-driven workflow designed specifically for these circumstances. The merit of the workflow lies in its systematic and methodical approach, providing solutions to various Geomechanical problems relevant to the target reservoirs, as well as the depleted reservoirs above and below. The results are beneficial for analogous fields where hydraulic fracturing is required to improve recovery of low permeability reservoirs in mature fields