Deepwater turbidite reservoirs have always presented several reservoir characterization challenges. Determining the complex architecture of the sand bodies, correlating them across multiple wells in the structure, and defining the sedimentological facies to determine the reservoir vertical communication and boundaries are some challenges in these Gulf of Mexico (GOM) turbidites. Other formation-related challenges of turbidite reservoir exploration and development include understanding reservoir rock quality and compartmentalization, as well as the identification of fluids. Deepwater exploration and development require innovative, cost effective evaluation technologies—technologies that help manage ultradeep and high-pressure environments. Having a detailed description of reservoir properties, fluids characterization, and a determination of the reservoir connectivity are crucial for understanding the reservoir and optimizing the field development plan. This study describes the wireline formation tester (WFT) operations performed in a harsh environment [ultradeepwater subsalt formation (> 32,000 ft) and high pressure (> 25,000 psi)] to obtain pressure data, establish gradients, evaluate vertical connectivity using vertical interference tests (VITs), check for compositional variation in different oil columns, and obtain clean formation fluid samples. Downhole fluid analysis was performed to help ensure the quality of formation samples and determine the fluid compositional analysis in real time during pumpout. To obtain high quality fluid samples while minimizing costs, an innovative technology—namely, a focused sampling probe—was used, eliminating the need for long pumpouts. Representative formation fluid samples were captured from three sample depths in approximately two hours per sample depth with minimum oil-based mud (OBM) contamination (< 5%). All the available openhole log data were integrated to understand the reservoir before running the WFT. Optimizing pressure and sampling depths (most representative intervals) can help reduce uncertainty when determining the number of pressure and sample points in the reservoir. Formation mobility, near-wellbore skin damage, reservoir pressure, downhole compositional fluid analysis, and reservoir connectivity were evaluated in a unique and challenging environment. Reservoir connectivity results from formation testing show good alignment with the presence of fractures and other sedimentary features from borehole image data. A similar methodology can be extended to other deepwater turbidite reservoirs in the GOM.

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.

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Knowledge of the minimum principal stress in the overburden is highly valuable – and even required – for well design, drilling, completion, plug and abandonment, and reservoir injection planning optimization. Access to an effective methodology whereby the stress could in principle be reliably determined at multiple arbitrary depths along the wellbore throughout the overburden is thus highly beneficial to more reliably predict the in-situ stress state. Within the reservoir, such data have been successfully acquired using straddle packer wireline tools, the socalled microfrac test. However, shaly overburden and cap rock formations in particular have very low mobility, therefore the induced fracture bleeds off at an extremely low rate after shut-in. This lack of formation leak-off and fracture closure renders least principal stress analysis difficult without a controlled pressure release option including sufficient volume control. The recent deployment of new technology enables microfrac tests to be successfully applied to tight formations. A new flow-back option has been deployed and utilizes the injection pump in reverse mode as a fluid expander which moves fluid from high to low pressure. Fluid injected into the fracture flows back to the borehole at a controlled rate, enabling high quality tight formation stress testing. A description of the new method and the first field implementation, which turned out to be a success case where data were acquired at multiple depths in a well on the Norwegian Continental Shelf (NCS), is given. The subsequent application of the results in terms of constraining the minimum horizontal stress and pore pressure models for the well is presented, illustrating the value of the tool and the microfrac stress data.

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.