To minimise well-count, sustain high injectivity and enable high offtake rates from the associated oil producers, cased-hole frac-pack water injectors in deepwater fields are often operated at relatively high injection rates. However, continuous injection at high rates (velocities) may displace the proppants in the sand-control system, increasing the vulnerability of such injectors to impairments by fines invasion. To mitigate this impairment mechanism, a new fibre-based product (interconnected fibre network) was recently introduced for locking proppants in-place. Although the product was extensively tested in the laboratory prior to its release, its field performance and impacts on injectivity remain uncertain. To improve the reliability and longevity of a critical frac-pack water-injection well in a giant West-Africa deepwater oilfield, this proprietary product was recently deployed. Being the first field application in the exploration-and-production industry, this case-study presents an opportunity to validate the results of prior numerical and laboratory experiments while identifying relevant improvement areas for future developments and field applications. Specifically, the impacts of this product on well injectivity and other performance indicators were investigated. Within 6 months of start-up, the well injected ca. 7 MMbbl of treated seawater and surveillance data acquired. Although this fibre-reinforced cased-hole frac-pack injector is still at relative infancy, this paper presents initial insights gained from managing the well. For the current evaluation, the surveillance techniques employed include the Hall-plot and deep-bed filtration analysis, complemented by step-rate, injectivity and pressure-transient tests. Among other findings, the performance of this well is generally comparable to the conventional (unreinforced) frac-pack injectors completed in an analogue reservoir in the same field. To a reasonable extent, this pioneering case-study allays the pre-installation concerns that the product would hamper injectivity. The present observations notwithstanding, there remain some key uncertainties and challenges, which are potentially reducible as more statistically significant performance datasets become available from this field and elsewhere. It is too early to conclude from available data that the fibre-reinforced frac-pack performs better than the (previously used) non-fibre-reinforced frac pack injectors in this field.
The Bonga North West (BNW) field is located in Shell operated Oil Mining Lease (OML) 118, a deepwater development in Nigeria. This paper presents the BNW subsurface development strategy and the associated uncertainty management both at planning (Field Development Plan -FDP) and execute phase.The first development in the OML 118 acreage is the Bonga Main field which came on stream in November 2005 via a Floating, production, storage and offloading (FPSO) vessel. The development strategy of the block is to maximize value from the asset, ensuring that the hub is kept full by developing reservoirs in the nearby fields while optimizing production from the block. In pursuant of this strategy, detailed subsurface evaluations were carried out to estimate expected recovery of the nearby fields as potential tie-backs to the Bonga Main FPSO. The size of nearby discoveries and proximity to the FPSO were two key parameters used to develop the OML 118 development strategy.BNW was discovered in 2003 following the detailed interpretation of 3D seismic acquired in 1995 on the acreage. Integrated evaluation across key disciplines established commercial viability of the project. This, coupled with a detailed geo-hazard study, formed the basis for the 2011 BNW FDP. The FDP proposed the field being developed with nine wells in two phases of drilling. The development phasing was driven by the requirement to manage the field uncertainties by gathering additional data. The first phase development involves six wells (four oil producers and two water injectors).BNW leveraged on its close proximity to the existing Bonga Main infrastructure and was approved as a subsea tie back development to existing Bonga Main FPSO. The FDP enabled a robust management of challenges such as shallow gas occurrence, structural/depth uncertainty, stratigraphic/reservoir development, reservoir connectivity, fluid prediction in the shallow horizons, bore hole stability and overburden shale issues encountered in the execution phase. Also a new technology that targeted managing of impairments in water injection wells experienced in the operation of Bonga Main field was also successfully deployed in the BNW field development. All Phase 1 development wells have been successfully drilled and several learnings from this project have been documented and will be used on projects going forward.
This study highlights a technique adopted for predicting and mapping net-to-gross (NTG) away from well locations through a combination of rock physics and seismic inversion applied in the Baza Field. The Baza field is located offshore Nigeria, with reservoirs poorly to mildly consolidated that were originally deposited in a deep-water submarine canyon system. The field is a partially appraised green field with three well penetrations encountereing amalgamated channels and lobes within the canyon system of tuiditic origin. Of the three wells drilled to date, only one well penetrated the key reservoir of interest- the B4 sands. The paucity of well penetration posses a challenge for accurate reservoir property assessment, particularly net-to-gross that has direct impact on hydrocarbon volume computation and ultimately on field development. Net-to-gross was predicted from seismic data based on a linear relationship observed from log derived P-impedance-AI (density × compressional velocity logs) and S-impedance-SI (density × shear velocity). Both properties when integrated can descrimate between sands and shales, and therefore serves as a proxy for calculating NTG. The linear relationship was applied to AI and SI seismic volumes built from simultaneous inversion of three sub-stack seismic data – the near (0-18), median (12-24) and far (24-45). The seismically derived net-to gross computed from simultaneous inversion compares favorably with log derived net-to-gross at well locations. The net-to-gross model resulted in a robust static and dynamic model that ultimately formed the basis for selecting optimal locations for future development wells for the B4 reservoir.
scite is a Brooklyn-based organization that helps researchers better discover and understand research articles through Smart Citations–citations that display the context of the citation and describe whether the article provides supporting or contrasting evidence. scite is used by students and researchers from around the world and is funded in part by the National Science Foundation and the National Institute on Drug Abuse of the National Institutes of Health.
customersupport@researchsolutions.com
10624 S. Eastern Ave., Ste. A-614
Henderson, NV 89052, USA
This site is protected by reCAPTCHA and the Google Privacy Policy and Terms of Service apply.
Copyright © 2025 scite LLC. All rights reserved.
Made with 💙 for researchers
Part of the Research Solutions Family.