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Wellbore instability challenges encountered while drilling the Nahr Umr Shale include, but are not limited to, hole collapse leading to hole enlargement. Wellbore instability leads to huge cost increases in the drilling process and in rare cases well abandonment. Observations from drilling data suggest that wellbore stability varies with different wellbore deviations and azimuths, especially in areas of highly laminated formations and anisotropic in-situ field stresses. Accurate information on the rock strength and rock failure behavior in shale has a major impact on the improvement of drilling efficiency. Knowledge of the mechanical properties of shale is essential to implement any 3D shale anisotropy borehole instability model (Crook AJL, et. al., 2002). Shale mechanical properties were evaluated from laboratory tests. Well-preserved core samples retrieved from the Nahr Umr Shale were put through several tests to describe the mechanical characteristics related to rock strength and in-situ stresses with the aim to determine the effect of the anisotropy and plane of weakness in drilling high-sailing angle trajectories. Strength anisotropy was assessed using the plane of weakness model (Jaeger, J.C., & Cook, N.G.W., 1979) which assumes that the heterogeneous media is composed of a matrix rock and a plane of weakness (e.g., bedding/laminations, interface between lithotypes or laminations). Shear failure occurs once the shear stress acting on the plane of weakness exceeds its shear strength. Laboratory tests include both extremely slow triaxial tests and multistress path testing performed on three orientations. Failure envelopes were created to develop the plane of weakness model to predict the orientation of the weakest plane and determine the magnitude of the strength reduction. Elastic anisotropy data from plugs is combined with advanced sonic logs, enabling a more robust evaluation of the formation anisotropy to improve both stress predictions and the allowable mud-weight windows during wellbore stability assessment.

Cenomanian carbonate deposits of Shilaif Formation, located west of Abu Dhabi, exhibit a high degree of heterogeneity at multi scales. To characterize this formation and explore its hydrocarbon potential, several geological, petrophysical, and geochemical analyses, including digital rock analysis (DRA), were applied and integrated. A hundred ft of whole core were logged at the surface using dual-energy X-ray CT (DECT) and Spectral Gamma (SGR) to generate bulk density, photoelectric factor, and gamma logs. Based on integration between DECT, SGR, and wireline logs, high-resolution total organic carbon (TOC), brittleness index, and mineralogy logs were generated at a millimeter scale, and representative core samples were extracted. Inorganic and organic geochemical analyses represented by X-ray diffraction, LECO TOC, HAWK pyrolysis, vitrinite reflectance, and hydrocarbons chromatography (SARA) were performed on selected samples to define rock mineralogy, type, and degree of organic matter maturity and chemical composition of the hydrocarbons. Nuclear magnetic resonance (NMR) at native, dry and full-brine saturation conditions, mercury injection capillary pressure (MICP), and crushed rock analysis (CRA) were conducted on selected samples to determine fluid saturations, porosity, permeability, and pore-throat-size distribution. The pore-scale analysis was also performed using argon-ion-milled SEM images to quantify organic matter contents and total, effective, and organic matter porosities. All core data obtained at multiscale were integrated with the wireline and generated high-resolution logs to validate and select optimal horizontal leg landing zones. DECT and SGR logs showed the top of Shilaif is mainly made of calcite, while its bottom is calcitic with minor concentrations of clay minerals and pyrite. Integration between DECT and SGR logs showed the mid and bottom of the formation have high radioactivity attributed to the presence of organic matter in intermediate concentrations and the presence of clay minerals. Pyrolysis analysis indicated a kerogen type I to II with an average Tmax equal to 431°C. Measured and calculated vitrinite reflectance (Ro) was, on average, 0.59, confirming that the kerogen of Shilaif in the area of study falls within the immature to the early mature oil window. Measurements such as CRA, MICP, NMR, and 2D SEM analyses showed that Shilaif has low porosity of approximately 3% on average and very low permeability averaging 0.00057 mD. The 2D SEM images and NMR data confirmed this and revealed that it lacks the porosity associated with the organic matter resulting from its low degree of transformation. Lab data and upscaled petrophysical logs showed that Shiliaf in this field has a low degree of thermal maturity and fall within the early oil window. Integration between core analysis results and wireline data helped understand the Shilaif Formation characteristics and determine its hydrocarbon potential. It also provided additional calibration to the wireline data.

Unconventional and conventional reservoirs do not have much in common. They exhibit different reservoir characteristics; therefore, using conventional reservoir interpretation techniques and workflows in unconventional reservoirs could lead to incorrect conclusions. In addition to fundamental challenges in evaluating reservoir properties, such as porosity and permeability, it is extremely important to understand reservoir fluid distribution. Downhole fluid typing and calculated volumes, together with porosity and permeability, provide more insight into reservoir potential and sweet spot zones. Nuclear magnetic resonance (NMR) technology can be used to provide answers to some of the unknowns mentioned previously. Standard NMR measurements provide the lithology-independent porosity and permeability, and then further processing provides more details about partial porosities, volumes, and fluid types occupying the pores. Using two-dimensional maps (2D NMR) helps differentiate the reservoir fluids, especially when distinguishing hydrocarbons (HC) from water. In conventional reservoirs, it is expected to observe faster relaxation for fluid trapped in the smaller pores and longer relaxation for free fluids in the bigger pores. Industry-accepted cutoffs for T1 and T2 measurements help estimate micro, meso, and macro pores. However, for unconventional reservoirs, fluid identification using 2D maps would be different. Fluids in the small pores, such as bitumen, heavy oils, or HCs in source rock reservoir, would have a similar signature on 2D maps. This paper presents two case studies showing how 2D NMR application was used in an unconventional reservoir for fluid typing processes and HC volumes calculation. It also shows the importance of using this method for more precise planning of further downhole activities. Core data analysis and downhole collected fluid laboratory analysis confirmed the high confidence in NMR fluid typing applications for unconventional reservoirs.

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.