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.

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.

EOR is a key focus area for sustaining long term production and maximizing of recovery in Raudhatain and Sabriyah oil fields of North Kuwait (NK). NK oil fields consist of multiple stacked reservoirs containing both clastic and carbonate with challenging temperature and formation water salinity conditions for Chemical EOR. In addition to these harsh conditions, reservoirs have geological structural complexity, reservoir heterogeneity and aquifer strength settings. Kuwait Oil Company is putting large efforts into Chemical EOR (cEOR) maturation through two ongoing ASP pilots and polymer flooding maturation studies. Ongoing studies and preliminary piloting performance results revealed that different reservoir segments have different cEOR requirements for viable incremental oil opportunities on top of ongoing water flooding. An expansion strategy has been developed that provides a view on how to transition from pilot results to larger scale commercial implementation of cEOR for each reservoir segment. This includes front end elements, beyond conventional cEOR screening studies, injectivity, conformance control, inorganic scaling, facility impact and pattern configurations. For larger scale, many additional aspects such as water source, well location, phasing, logistics and impact of back production are important factors. For commerciality, there needs to be abalance between schedule, maximizing economic recovery, operability,availability of source water and costs. A holistic, structured approach has been established in defining production forecasts and life cycle cost estimates for ASP, SP and polymer development concepts screening for major NK reservoirs. The approach has allowed comparison between recovery methods and reservoirs which helped in defining an EOR expansion plan. The novelty in this EOR expansion strategy is in application of a structured and holistic approach to map viable cEOR technologies to different reservoir segments based on in-depth screening criteria. The methodology allowed generating "standardized" time bound forecasts and cost estimates for screening a range of viable mapped cEOR methods for a range of reservoir segments- facilitating like for like comparison.

An inverted 5-spot Alkaline Surfactant Polymer (ASP) pilot is planned for a giant sandstone reservoir in North Kuwait. Despite the development of a robust lab-optimized ASP formulation at reservoir temperature (90°C) and the execution of a successful Single Well Chemical Tracer Test (SWCTT), the combination of high temperature and divalent ion concentration (∼20,000 ppm) makes the implementation of a successful multi-well ASP pilot very difficult mainly due to the challenge of inorganic carbonate scale. This paper presents some unique challenges in connection with the design of an inverted 5-spot ASP pilot and discusses practical strategies to mitigate them. Due to the high divalent ion concentration in the formation brine, the design basis for the planned chemical EOR pilot requires pre-flushing the reservoir using softened seawater prior to ASP injection. In the base-case scenario for the pilot, injection and production within the pattern were balanced to target a Voidage Replacement Ratio (VRR) of 1. However, it was realized that such a pre-flush strategy would still present significant carbonate scaling risk at the producers. In view of that, an extended softened-water pre-flush strategy (over-flush) was considered to alleviate the anticipated scaling concerns. Simulations were carried out to explore various scenarios to work out the optimal over-flush strategy for the pilot to mitigate the potential for scale formation at the producers. It was realized that over-flushing the hot reservoir brine by large volumes of cooler surface water could result in significant cooling of the reservoir prior to ASP injection. This change in reservoir temperature compromises the performance the original lab-optimized formulation that was designed considering a reservoir temperature of 90°C. In view of that, careful re-tuning of the chemical formulation was necessary to make it robust for pilot conditions post softened water over-flushing.

A regular 5-spot Alkaline Surfactant Polymer (ASP) pilot is planned for a giant carbonate reservoir in Kuwait where a suitable formulation compatible with harsh salinity and temperature conditions was developed. However, it is vital to address uncertainties introduced through historical development schemes that are not necessarily compatible with original EOR plans. This paper sheds light on the importance of incorporating water flooding data and learnings to optimize the design of subsequent EOR deployment. An integrated workflow was adopted involving acquisition and analysis of relevant surveillance data to establish a solid understanding of water flooding preceding EOR deployment. The considered surveillance data covered pressure responses, rates, a variety of passive tracers, injection step rate tests followed by fall off tests, production/injection logs, high precision temperature logs, spectral noise logs and water injection into reservoir cores. The extent of thermal and reservoir depletion effects on reducing fracture initiation pressure was also investigated. The study focuses first on understanding the microscopic and macroscopic aspects underlying overall sweep efficiency due to water flooding, a key requirement to upscale the Pilot results to full field development. The macroscopic sweep efficiency was found to be strongly affected by the native permeability contrast attributed to geological heterogeneities as well as induced fractures. Induced fractures were triggered by different mechanisms related to cold water injection, reservoir pressure depletion, injected water quality and relatively high injection rates targets for a comparatively low permeability carbonate reservoir. The findings related to induced fractures have a well-established impact on the design and operating philosophy of the desired ASP Pilot with relatively short well spacing and active surrounding production/injection wells. Premature breakthrough of chemical injectants will not only impact the sweep efficiency of ASP flooding, but will potentially bring about operational complications due to inorganic scaling and produced fluids separation, thus introducing additional uncertainties in relation to the acquisition and interpretation of the Pilot data. The original Pilot design is being revisited by means of an integrated workflow to better understand and adequately mitigate poor conformance challenges during the softened water injection phase that will be followed by the ASP injection phase using a fit-for-purpose surveillance program. This workflow involves geological characterization and detailed analysis of water flooding performance in pursuit of improved conformance control to pave the way for efficient ASP flooding. The findings of this study underscore the importance of integrated field development planning and comprehensive surveillance to derive important waterflooding insights that can be used to de-risk ASP flooding under harsh reservoir conditions.