Population and economy are two key factors considered in global energy demand projections. With rapidly growing world population, energy security is a global concern. The 2011 World Energy Outlook projected that from the 2010 levels, global oil demand will grow by 14% while gas use will rise by more than 50% as well as account for over 25% of world energy demand by 2035. With hydrocarbons no longer easily accessible, success in the future of oil and gas will require meeting various challenges, including ensuring that both discovered and new resources can be produced in economically and environmentally sound manner to offset the natural field decline. Also, shareholders, non-government organizations and local communities are seeking for more value and demonstration of social responsibilities from the industry. Additionally, governments and policymakers are imposing stricter regulations that impact reserve maturation and production.One of the ways stakeholders' expectations can be addressed is by making the most use of resources to lower costs and improve operational efficiency. Lean is a business improvement technique with a collection of tools to eliminate ''waste'' in an operation and reduce cycle time. Cost reduction is achieved by improving the flow of material and information through the system and continuously finding ways to reduce the amount of work by taking out unnecessary or "waste" steps in processes. Originally developed by the Japanese automobile company, Toyota and widely employed in the manufacturing industry, more industries are adopting the Lean concept.This presentation will showcase Lean application in hydrocarbon development and production. Case studies will be provided to demonstrate how Lean implementation has helped and can be used to eliminate wastes in processes and bring about a culture change. Business results are SPE 162995

IPM offers a cost effective technique for assessing and optimizing field development concepts, it allows for evaluation of various scenario plays whether they be well pairing, well count, well phasing, subsea layout, pipeline sizing, flow stream scheduling or process configuration to achieve maximum recovery of any particular fluid stream. IPM can also be used as a change management tool during the execution phase of a development project to understand the impact of change on the system. The petroleum experts (PETEX) modeling tool has been employed for the evaluation of the Bonga North deepwater subsea tie-back development, the software enables the integration of flow assurance with subsurface deliverability and the topside constraints (both envisaged and existing) for all considered options. The tieback development was designed as a haulage filler to an existing Bonga FPSO and hence the IPM model was built to provide answers to pertinent development and production concerns such as the best timing for bringing the tie-back development on stream and the impact of the tie-back on the host field production and recovery. This paper describes the structure of the IPM model and its various components, it also highlights some of the benefits and challenges of deploying IPM for field development optimization using the PETEX GAP production modeling tool coupled with an in-house reservoir simulator.

Summary Bonga field in deepwater Nigeria produces hydrocarbons from classic deepwater turbidite reservoirs deposited in channel settings. The reservoirs consist of a series of amalgamated channel complexes with varying degrees of compartmentalization. The depostional configuration presented significant uncertainties in connected volumes, well placements, and sweep efficiency between water injector/producer well pairs. However, because of the high costs of deepwater developments, well count needs to be as low as practical, and production rates must be sustainably high to ensure economic robustness of the project. High rates and high ultimate recoveries are the foundations of successful deepwater projects. At Bonga, constant pressure maintenance is a key component to achieving high-rate, high-ultimate-recovery wells. Several research studies concluded that the required water-injection wells be designed for fracture injection (i.e., above sandface-fracture pressure) to sustain the required high rates, as opposed to reservoir matrix injection. This paper presents the results of these research efforts leading to this conclusion and the implications on reservoir management. Also presented is an overview of the challenges of developing these complex channel deposits and the new approach to modeling high-rate wells in deepwater turbidites. Key to successful understanding of reservoir behavior (connectivity) and early indications of future reservoir performance is a systematic undertaking of interference tests at production startup. After approximately 2 years of production, the results from the Bonga wells demonstrate that sustained high oil rates could be achieved with adequate pressure maintenance. Average oil production rates of vertical/deviated wells range from 15,-00 to 22,000 BOPD and that of horizontal wells range from 25,000 to 35,000 BOPD. Estimated ultimate recovery (EUR) per well ranges from 20 to 100 million STB for Phase 1 wells and from 10 to 30 million STB for Phase 2 development wells, with several additional opportunities for infill drilling of lower-EUR wells. Nameplate capacity of 225,000 BOPD was achieved and sustained with just nine producers and six injectors. To maintain these high production well rates, world-class water-injection well rates (of between 40,000 and 70,000 B/D per well) have been sustained since first oil. The fracture-injection approach is applicable both for onshore and offshore reservoir development but, more significantly, for deepwater reservoir development in which sustained high rates and economic considerations are paramount. Introduction The Bonga development is targeted at four major Lower-to-Upper Miocene channelized turbidite reservoirs (A, B, C, and D), each with varying degrees of amalgamation. The Bonga reservoirs lie on the western flank of the shale-cored Bonga anticline and are trapped stratigraphically and structurally in mud-rich, unconfined turbidite systems in a mid-lower slope setting. The reservoirs consist of unconsolidated fine-to-medium-grained turbidite sand deposits with reservoir permeabilities ranging from 200 to more than 5,000 md. Pre-first-oil production-test interpretation results suggested permeabilities in the 2,000-7,000-md range, and production indices (PIs) in the 70-140-(B/D)/psi drawdown range for vertical/deviated wells and over 350 (B/D)/psi drawdown for horizontal wells. The reservoirs are mainly hydrostatically pressured to mildly geopressured, and reservoir fluids are undersaturated in gas with undersaturation spreads (reservoir to bubblepoint pressure) of 500 to 2,000 psi. To keep production rates high and to keep the reservoirs from going below bubblepoint, water injection for pressure maintenance was required from Day 1 of productions. Table 1 summarizes the typical rock and fluid properties of the various reservoirs. With such a combination of excellent reservoir and production-fluid properties, achieving high initial oil-production rates was not a challenge in this field. In contrast, the main challenges wereSustaining high oil rates over time with adequate injectionMaintaining sand-control integrity in the well completionsDemonstrating that reservoir discontinuities associated with fault compartmentalization and stratigraphic compartmentalization associated with turbidite channel complexes would not exceed predicted levels Item 2 was addressed by the application of various sand-control measures, including fracture and pack (F&P) for vertical/deviated wells and openhole gravel pack (OHGP) for high-angle/horizontal wells with adequate wellbore-integrity modeling. Item 3 was addressed through careful well-placement strategy with injector/producer pairs located in the same fault block, limiting the injector-to-producer spacing as much as was possible to 1.5 to 2.5 km. Item 1 in the list is the primary subject of this paper and is discussed later in detail. This paper presents strategies adopted to ensure sustained injection of treated seawater to maintain reservoir pressure greater than the bubblepoint.

New Technology implementation brings intrinsic value to well delivery projects with enhanced capabilities for exploitation of hydrocarbon reserves. However, the planning of wells with new technology applications, especially in remote operating locations, comes with unique challenges of compatibility of existing equipment and unavailability of equipment required for the new technology system's deployment. This paper presents a case study of an engineered approach to equipment modification and retrofitting of wellhead equipment to achieve the required compatibility with a new technology solution identified for a well as a pilot. The limiting conditions encountered in the new technology implementation as presented in the case study are discussed together with the analysis of available concepts to resolve the ensuing gaps and the engineering design of the retrofit solution. The approach not only resulted in significant cost savings but has attendant value creation benefits. The methodology and thought process presented can be deployed to solve challenges that engineers are confronted with while planning, especially with new technology applications in remote operating environments as was used by OML 26 Asset in the installation of the first ESP artificial lift in the Ogini field.

Managed by a joint operating team tagged the Asset Management Team (AMT), the OML 26 Asset has undergone a total transformation in all ramifications of the oil and gas operations. Within the space of three years, the Asset has recorded a 122% cumulative annual growth (CAGR) for reserve base increase, a 43% CAGR in production rate increase without drilling new wells, and a 38% CAGR in total production offtake. The direct unit operating cost also improved significantly averaging 31% year on year improvement. From Q4 of 2018, the Asset witnessed breakthrough performance attaining a peak production of ca 18,000 bopd in 2019 from existing drainage points. The rate is the highest rate ever recorded in the long history of the Asset. This is an excellent achievement for a mid-sized E&P company. This paper aims to share the techniques deployed to attain such a sterling production boost in a 45-year-old field.