The Ormen Lange Field is a gas reservoir offshore mid-Norway, developed in a combined structural–stratigraphic–hydrodynamic trap. The lobe-dominated turbidite deposits are mostly of excellent quality, but show a significant deterioration trend towards the fan fringe at its northern margin. Axial parts of the fan contain amalgamated sand-rich deposits, which pass laterally into layered sequences characterized by intercalation of low-permeability heterolithic drapes. Along its 40 km length, the field contains in excess of 400 linked polygonal faults attributed to de-watering of underlying shales. Despite pervasive faulting, reservoir connectivity on a geological timescale is proved by a common pressure gradient in pre-production wells and depletion seen in all later development wells. Recent appraisal drilling of the fan fringe, occupying the crest of the field, encountered only residual gas saturations, despite being located in an area delineated by a seismic direct hydrocarbon indicator. A hydrodynamic aquifer concept is the most plausible explanation for the fluid distribution, in which the gas from the crest of the structure is displaced, leaving behind a northward-thickening prism of residual gas. Dynamic simulation of the fluid-fill evolution over geological time showed the hydrodynamically tilted contact depends on rate of water flow across the aquifer, stratigraphic baffling and faulting, and reservoir quality, i.e. clean sand fraction and effective permeability. Optimal development of this deep-water reservoir depends on understanding the relationship between reservoir quality, connectivity, and the position of the free water level (FWL) in the field. A range of FWL in the north of the field, only weakly constrained by the wells, was empirically established from the hydrodynamically initialized models. This allowed a robust test of the production wells planned to drain the margin of the field. Modelled predictions of reservoir quality and pressures were confirmed by subsequent drilling.

The GOGD recovery mechanism in fractured reservoirs consists of taking advantage of gravity to develop the oil stored in the matrix through the management of the position of an oil rim within the fractures, where producers are placed. Gas oil gravity drainage is an effective method to increase ultimate recovery but it is a slow process. After 50 years into the development of a giant oil field in Oman, a new strategy for placement of additional GOGD wells is proposed, with the objective to optimize the performance of specific layers and achieve top quartile performance. The understanding of a complex fractured field is based on a thorough data analysis phase with a focus on the total picture, the conceptual interpretation of 50 years of history, the successes and the failures, to locate the remaining oil1. The data itself reveals the fluxes of the fluids within the reservoir and the physics of the recovery mechanisms taking place at all scales (mega-scale, meso-scale and micro-scale). The insights on reservoir plumbing have enabled the identification of in-fill opportunities through a better definition of faults & fracture maps and an updated fluid-fill concept (for matrix & fractures) explaining post-production contacts variability. We have described a new well placement strategy to target parallel GOGD processes happening across scales, and specifically within the background fracture network confined between fault corridors and mechanical shale barriers, in what we call "matrix blocks". Conceptual box models have been constructed to prove feasibility of the new development strategy through dynamic simulation. The infill development has been phased according to the ranked risk assessment of every specific location and the value of information it can provide for successive phases targeting smaller matrix blocks or more uncertain remaining oil. Standard GOGD practice in intensively fractured reservoirs is to manage the final position of the fracture oil rim, gas and water contact within the fractures, through managed gas injection and potentially aquifer pump off wells. We hereby propose the infill drilling of additional shorter horizontal wells avoiding major fracture corridors, placed above shales at the bottom of geological sequences to maximise gravity head and fluid hold up at discrete matrix blocks. Such wells are not at field wide final oil rim depth and they do not intend to target matrix sweet spots but rather accelerate the recovery of unfaulted stacked units.

This paper discusses the interpretation of historic data for a giant and COMPLEX fractured carbonate, leading to a different understanding of the reservoir's displacement processes, and renewed insights for future development opportunities. Specifically, the paper describes a comprehensive study to Locate The Remaining Oil (LTRO) and improve the ultimate performance of the field. The study encompassed the integration of recent seismic datasets, BHI (Borehole Imaging) data from over 100 wells, well logs for key wells at different time lapses, core data for different facies, well performance and interference data. Focus has also been placed on understanding the various recovery mechanisms that the field has undergone (water injection and Gas-Oil Gravity Drainage (GOGD) concurrently in different regions of the field). This LTRO exercise has provided insights into the distribution and intensity of inter- and intra-faults and the fracture connectivity between the field units. This warrants clustering the giant field into "development districts" i.e. to move from layer-based development to acknowledgment of vertical communication between layers It has become apparent that the reservoir architecture and fluid flow characteristics in this giant reservoir benefits from a secondary system of background fractures. The future field development concept should target- the matrix blocks with background fractures holding remaining oil for a slow GOGD development. The study is part of continued efforts to build a centre of excellence in PDO around Naturally Fractured Carbonate Reservoirs, and to help unlock reserves in PDO's extensive portfolio of NFR (Naturally Fractured Reservoir) Carbonate fields.

The development of thin oil rims in carbonate reservoirs requires good understanding of structural setting, reservoir architecture and transition zone saturations. Fields that have a tectonic and/or geochemical history after initial charge are likely to challenge standard assumptions of fluid distribution, contacts and saturation-depth relationships. This paper is a case study illustrating downflank field extension opportunities in an oil rim, related to post-charge tectonics affecting fluid distribution and contacts. The structure of this article encompasses four different aspects:begins by explaining the geological concepts that are being postulated for downflank hydrocarbon potential,proposes the alternative methodology of concept-driven analysis for log data interpretation,explains in detail the methodology applied to existing field data for reservoir architecture and fluid fill description,summarises the outcome of the appraisal well with respect to alternative concepts. The workflows that justified the placement of appraisal wells downflank followed the philosophy of concept-driven analysis where data is used to eliminate hypothesis rather than averaged into one a-priori assumption or average fitting equations. The placement of the pilot appraisal well (at a depth interval and location where previous models predicted water-fill) has been enabled by the identification of stratigraphic rock types, regional variability of fracture intensity and the prediction of tilted contacts. The results of an appraisal well drilled in 2017 confirm the alternative concepts proposed from concept-driven analysis of legacy log data:–Flank reservoir thickness improvement due to post-deposition crestal erosion of best facies.–Fracture density reduction towards the northern flank of the dome structure.–Tilted oil contacts deepening towards the flank and related to paleo-charge.–Relatively dry oil production from deeper depth intervals with low oil saturation due to transition zone water mobility. The drive mechanism and development options for the field should be investigated further.

The infill potential of a waterflood project in a transition zone carbonate reservoir has been revised through the usage of logging while drilling (LWD) data in horizontal wells. The North-Western flank prospective has been unlocked by unravelling lateral variations on reservoir architecture and generating an alternative fluid fill concept for transition zone saturation. The field is developed through horizontal wells with only five vertical penetrations that are clustered in the southern part of the field. Data analysis of the vertical wells supports the log response calibration, relating architecture and fluid fill to saturation models. The high density LWD data allows the coverage of the North Western flank. An alternative fluid fill scenario related to tectonic structural changes after charge (as previously published in 2016, SPE 181401) is consistent with vertical wells and LWD data and reflects an upside for the North-Western flank saturation. The alternative fluid fill concept reflecting post-charge tectonic changes of the structure has improved the North-Western flank saturation and infill potential. With the alternative concept, now in alignment with actual LWD measurements, the history match of the oil production of the flank sector has been achieved. An appraisal well is planned to assess the potential of the area.