fax 01-972-952-9435. AbstractThe economic recovery of hydrocarbons from deepwater reservoirs continues to be a major challenge facing the exploration and production industry, not just contending with the multitude of market uncertainties, but also, more importantly, reservoir deliverability uncertainties associated with deeply deposited pay targets. One large field subject of this study is such, deposited in stacked Pliocene sandstones. These are high net-to-gross, with predominant very finegrained sands. The efficient sweep of the oil in place requires a detailed understanding of the network of the reservoir pore structure, and the permeability distribution and capillary bound fluids.To better understand and characterize the permeability and to help quantify the potential reserves, a novel low gradient magnetic resonance LWD tool for application on conventional drilling assemblies was used. This is a major departure from the more conventional techniques which use high gradient magnetic resonance on post-drilled wireline platforms. Advantages of an LWD approach are twofold; the wellbore is in good condition at the time of drilling, yielding high quality data, and the gain in rig time is significant.The high quality magnetic resonance dataset acquired was confirmed by overlaying with stationary measurements. The data was integrated with offset core data to normalize permeability models and saturation functions. LWD density images acquired during drilling were also used to provide detailed visualizations of the internal laminations of the turbidites, as well as a reservoir structural setting. Formation pressures and mobility measurements acquired during drilling were also integrated in the normalization process to characterize the deliverability of the sands. The resulting permeability model was used to study and redesign future development in the field. The saturation results also provide an improvement over the previous resistivity-only based saturation values, which were pessimistic due to the fine-grained structure of the reservoir sands.

In January of 2008, Shell began drilling an extended reach exploration well from the Mars tension leg platform (TLP). This was an ambitious undertaking with targets nearly 20,000 ft (6,096 m) away in an unexplored fault block. Because of the high inclination of the borehole and the shallow depth of the objective sands, any geological uncertainty in the targets jeopardized the success of the project.While surface seismic is used to evaluate potential targets, it lacks the resolution needed to reliably place those targets. Different seismic processing techniques are available, but the validation of each model requires additional information. True vertical depth (TVD) and true vertical thickness (TVT) synthetic ties created from realtime logging data can improve that resolution. By employing a method that uses TVT, the synthetic ties better match the seismic model allowing for updates to the well path and precise placement inside the target. Multiple velocity models are also incorporated to obtain better time-to-depth relationships and to better predict pore pressure anomalies.In extended reach wells, small issues in the beginning can escalate into more serious problems at total depth. The well path, dogleg severity, and casing shoe placements must be optimized, leaving room for the possibility of changes due to unexpected events. Bottom hole assembly (BHA) design is also a key success factor. Acquiring the needed information in realtime to update the seismic model, while also factoring in tool reliability and planning for shoe-to-shoe performance, is critical. Further, at these high angles, it is important to drill a smooth and continuous borehole to reduce torque and allow for better casing runs. This paper describes how the geological, mechanical, and economical uncertainties were identified and minimized through well planning and the use of realtime data. Specifically, this paper addresses those uncertainties, associated risks, and the methods to minimize them in the A-8 well.The authors examine the pre-well work undertaken with the seismic data and how the BHA and well plan were designed to allow for possible changes. In addition, they will discuss how all the data were used to continually update the model and reduce geologic uncertainty as the targets were approached. Answers were provided in time to update the well path, increasing the chances for success, and ultimately meeting the well objectives.

The response of NMR in the unconventional gas play in the Beluga formation of the Cook Inlet basin at Ninilchik Gas Field does not match the conventional predicted pressure and temperature model, because the zones are at a relatively shallow depth of 1500 to 3200 vertical feet and the pressure gradient is approximately 0.44 psi/ft. This paper presents insights and results of applications of NMR in these unconventional low-pressure hydrocarbon formations. The integration of NMR with other LWD logs, including density, neutron, and acoustic, showed the need for combined petrophysics and petrofacies interpretation. NMR measurements exhibited that the free-fluid T2 cutoff was around 110 ms, well above the usual 33 ms for sandstone. Low pressure gas produces an NMR signal that not only is weaker but one that also relaxes faster than it does at high pressure. This is because of reduced hydrogen index and enhanced diffusion effects as pressure reduces. The crossover of density and NMR porosity curves was used to identify the pay zones. The difference of the porosities is due to the gas hydrogen index effect, resulting in a crossover similar to density and neutron crossover. Unlike neutron, NMR porosity is mineralogy independent. Therefore, it may be more reliable than neutron-density crossover to identify gas. Porosity and gas saturation were computed based on the differences between apparent density porosity and apparent NMR porosity - the density and NMR crossover methodology (DMR). Density and neutron logs were acquired while drilling and in the presence of dissolved gas trapped in formation porous space. Using the equations summarizing density and NMR porosity log sensitivities, the DMR method was applied to correct for the gas effect. The DMR method, with the help of additional logs such as neutron and density, enhances the understanding of NMR responses on these formation conditions. Once DMR porosity is computed, the free-fluid index can be recomputed to its actual value after gas correction; and gas-corrected permeability can now be estimated from the calibrated Coates-Timur model. Gas-corrected porosity and NMR permeability improved accuracy in determining the actual lithology.

From exploration to development, the challenges of costeffective exploitation of hydrocarbon reservoirs are enormous and diverse. A lack of detailed understanding of the petrophysical building blocks of the reservoir in the early stages of its development usually constitutes a major impediment to achieving an efficient development strategy. In addition, stratigraphic and structural uncertainties exist and are only minimised as more wells are drilled to develop the reservoir. The hydrocarbon fluid types, accumulation, and stratification can also present complex uncertainties in identification and quantification, depending on the depositional environment of the reservoir.The EE reservoir is structurally a rollover anticline with shallow marine deposits. It was discovered in 1965 and was put on stream in 1970. The reservoir has had 12 drainage completions to date, 7 of which currently flow with a total daily production of 7,100 BOPD. Until 1998, completion and development had been based on conventional data acquired at various time since the reservoir was discovered.In 1998, a new nuclear magnetic resonance (NMR) logging device was run in the reservoir for the first time. Logs were acquired in well XT, which penetrates the southeastern flank of the reservoir. The results provided an improved definition of fluid flow units in the reservoir. The effective porosity was found to average between 32 and 34% with less than 2% variation across the reservoir. However, the bulk volume irreducible (BVI) showed considerable variation with depth across the reservoir, defining an egg-shaped flow-unit body. Permeability was on the order of 1.0 darcy, while the clay spectrum indicated laminated interbedded shales with clean sandstone layers cutting across the upper section of the reservoir. Core data from a nearby well was integrated with the NMR results, and a good correlation was obtained. Implications of these data on future completions and reservoir drainage strategy are highlighted in the paper.

Optimizing Oil Recovery requires understanding of formation wettability; numerous characteristics of reservoir performance influenced by the oil versus water wetting preferences mainly in Enhanced Oil Recovery (EOR) practices and water flooding assuming a water-wet reservoir, if it is not, a permanent reservoir damage is expected. Oil Companies depend on the Core-Measured-wettability. The practice of transferring the samples from the formation to the lab may lead to wettability alteration during core cutting operations and sample preparation; additional laboratory issues include surface adsorption equilibrium and optimal interface-ageing time, if a smooth surface is used it will not account for the rock surface roughness. The biggest disadvantage of the laboratory methods is that of scaling to entire reservoir extent downhole condition. Adding up, all of these processes are time-consuming, consequently a technique to evaluate in-situ wettability is desired. The in-situ wettability of rocks from Nuclear Magnetic Resonance (NMR) log is a representative of the entire interval at the reservoir condition. A derived spin-lattice function from the fundamental NMR relaxation time T2 is directly related to the interfacial tension and the surface wetting fluid properties, as a result, an in-situ wettability index could be computed from the function. Rock wettability may explain some apparent discrepancies that occur in defining water-oil contacts by Reservoir Characterization Instrument (RCI) and logging measurements. Analyzing these discrepancies using the RCI Pressure Data makes it possible to estimate the In-Situ Wettability state of the reservoir. Case Studies from two different Giant Oil Fields located in the South of IRAQ are included in this paper, and each field has various sets of Data, varied from Pressure Test and NMR to only Full-Set of Wire line data. These fields were selected to represent various applications scenarios of Carbonate and Shaly-Sand Oil Bearing Formations of In-Situ Wettability using Nuclear Magnetic Resonance (NMR) log and Reservoir Characterization Instrument (RCI) Pressure Data. The novelty of this study offered advance integrated petrophysical evaluation for In-Situ Wettability to support the field development plans and improve the reservoir characterization.