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.

After 40 years of depletion drive, a mature, giant and multi-layer carbonate reservoir is developed through waterflooding. Oil production, sustained through infill drilling and new development patterns, is often associated with increasingly higher water production compared to earlier development phases. A field re-development plan has been established to alleviate the impact of reservoir heterogeneities on oil recovery, driven by the analysis of the historical performance of production and injection of a range of well types. The field is developed through historical opportunistic development concepts utilizing evolving technology trends. Therefore, the field has initially wide spacing vertical waterflooding patterns followed by horizontal wells, subjected to seawater or produced water injection, applying a range of wells placement or completion technologies and different water injection operating strategies. Systematic categorization, grouping and analyzing of a rich data set of wells performance have been complemented and integrated with insights from coarse full field and conceptual sector dynamic modeling activities. This workflow efficiently paved the way to optimize the field development aiming for increased oil recovery and cost saving opportunities. Integrated analysis of evolving historical development decisions revealed and ranked the primary subsurface and operational drivers behind the limited sweep efficiency and increased watercut. This helped mapping the impact of fundamental subsurface attributes from well placement, completion, or water injection strategies. Excellent vertical wells performance during the primary depletion and the early stage of water flooding was slowly outperformed by a more sustainable horizontal well production and injection strategy. This is consistent with a conceptual model in which the reservoir is dominated by extensive high conductive features that contributed in the early life of the field to good oil production before becoming the primary source of premature water breakthrough after a limited fraction of pore volume water was injected. The next level of analysis provided actual field evidence to support informed decisions to optimize the front runner horizontal wells development concept to cover wells length, orientation, vertical placement in the stratigraphy, spacing, pattern strategy and completion design. The findings enabled delivering updated field development plan covering the field life cycle to sustain and increase field oil production through adding ~ 200 additional wells and introducing more structured water flooding patterns in addition to establishing improved wells reservoir management practices. This integrated study manifests the power, efficiency and value from data driven analysis to capture lessons learned from evolving wells and development concepts applied in a complex brown field over six decades. The workflow enabled the delivery of an updated field development plan and production forecasts within a year through utilizing data analytics to compensate for the recognized limitations of subsurface models in addition to providing input to steer the more time-consuming modeling activities.

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A mature and congested field with multi-stacked sandstone reservoirs has been developed through depletion drive for 50 years and more recently with peripheral water injection. Currently, the field performance shows rising water-cut in some reservoir units and pressure depletion in others, but still has significant remaining development potential. A field development plan has been established to economically produce bypassed oil, driven by the analysis of the historical performance data for the different reservoir units. Integrated analysis of historical data and development decisions identified the subsurface and operational drivers behind the increased water-cut and differential pressure depletion. This paved way for developing clear recommendations for the major development decisions on well and completion type, well spacing and waterflood strategy. Oil production type curves generated for each reservoir unit using recent infill drilling historical production data helped establish the preferred development phasing and production forecasts. Urban planning is a key enabler to realize value from the future development of the field due to surface congestion; therefore, the new wells have been allocated to multi well pads. The detailed analysis focused on each area of the field, complemented with saturation logs and dynamic model, helped in determining the long-term well requirements and their locations targeting bypassed oil. The integrated study generated a rolling development plan covering the field life cycle to accelerate oil production and reserves maturation and improve the reservoir pressure and sweep. Each new well has been assigned a primary reservoir target and a confidence level for the target reservoir to enable phased implementation of structured infill drilling to reduce well spacing starting with high confidence wells. New water injectors were added to the reservoir units that have limited aquifer support. Integration of the well pad allocation and development schedule with the pad construction schedule helped identify and mitigate against any surface related showstoppers to the planned well locations and the development schedule. As a result, more than 130 new development wells were added to accelerate oil production and increase production rates. This integrated study manifests the power, efficiency and value from brownfield data driven analysis to capture lessons learned from evolving wells and development concepts applied in a complex field over six decades. The workflow enabled the delivery of an updated field development plan and production forecasts within a year through utilizing data analytics to compensate for the recognized limitations of subsurface models. Urban planning and multi-well pad drilling concepts alleviate the impact of drilling constraints.

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