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.

The era of easy oil is coming to an end, a lot of the major reserve finds these days are located in very challenging operating environments such as deep and ultra-deep water. Subsea tie-back systems over the years have evolved as a solution to the challenge of harnessing these reserves in a cost effective manner. The challenges for subsea type developments are not only limited to the cost of drilling and infrastructure or the complexity of the subsea layouts but also the technology of assessing and producing the volumes to surface poses a great challenge. Production technology challenges include multi-phase fluid flow, completion design, flow assurance (hydrate mitigation & management), well intervention and long term well monitoring. Of particular concern are the issues of water-flood management, intelligent completion & production systems which are core to achieving increased ultimate reservoir recovery and production volumes required for cost effectiveness. This article highlights the major production technology challenges articulated for a typical long subsea tie-back development and discusses how these could be managed.

Reservoir sands in the deepwater formations in West Africa are largely soft and unconsolidated based on data from producing fields and preliminary studies on upcoming developments. Studies have shown that fractured injection in unconsolidated sands is different from hard rock fracturing in which case a single dominant fracture is created during injection. For unconsolidated sands, smaller fractures are created to bypass impairment and much of the injection may be under matrix rather than fractured conditions. Given the importance of waterflood to most projects, it is imperative to understand the dynamics of fractured injection in this type of sands and all the factors that can impact on the effectiveness and efficiency of designed waterflood systems. This is even more important for upcoming projects whose viability may depend on the delivery of high rate – high ultimate recovery wells which can only be supported by an effective pressure maintenance /voidage replacement system. In this paper we present a study carried out on one of such developments (turbidite reservoirs in Deepwater West Africa) for which a water injection program is to be designed. The modeling work is highlighted and the effect of different parameters on fracture growth propagation and injectivity were analysed.

As more subsea projects mature and with increasing understanding of operations involving subsea wells, the industry is constantly faced with the constraints and challenge posed by the requirements for metering, sampling, well testing and allocation. These challenges are even more pronounced in cases where flow assurance issues play a role especially for long tie-back systems. Current regulation in the Nigerian sector has yet to catch up with these developments and as such operators struggle to meet the requirements. A number of possible solution to the seeming problems or issues are under study, and with updated knowledge of the systems, it has become imperative to articulate and formulate strategies and philosophies for resolving or addressing the metering challenge for operations in Deepwater Nigeria. This article analyzes one of such solution in the application of subsea multiphase flow meters Introduction Subsea systems have evolved over the years, as a major solution to the technical and commercial challenge of harnessing reserves in the deepwater terrain. With the ability to extend tie-back distances, it affords a perfect means of achieving hub strategies allowing for continual development of reservoirs at great stepout distances. As stepout distances increase so does the challenge of delivering the hydrocarbon to the host facility. Flow assurance issues are key and often compounded by unwanted deposition such as hydrates, wax, scale and asphaltenes in the transportation and processing system components. This makes the task of measuring and quantifying the volumes of hydrocarbon products difficult. The traditional method is to measure these product quantities at the host, via test separators. The accuracy of the flowstream measurements is however a function of the stability of the system, requiring the introduction of artificial lifting systems (in most cases riserbase gaslift is employed). Operational experience with subsea production testing reveal that there are threshold rates required for stability. Below these threshold, serious system upsets such as slugging, impacts on the production system sometimes causing a shut down of the facility.

Coarse scale modeling of deepwater turbidites requires that effective properties be developed to capture the fine scale flow behavior. In displacements with unfavourable mobility ratio, displacement instabilities at the shockfront may exist resulting in the occurrence of viscous fingers that reduce breakthrough recovery and increase gas and water production. Viscous fingering effects have been studied and demonstrated by laboratory experiments. The practical scale of fine scale models is usually too large to resolve viscous fingering effects. Hence evidence of viscous fingering has to be tested and appropriate upscaling applied at the fine scale modeling stage. A two stage upscaling technique has been developed for heavy oil effective flow properties determination, a viscous fingering correction and generation of dynamic pseudos. The viscous fingering correction was done using the method of Clemens and Wit. This assumes that viscous fingers can be described by using a segregated flow approach. Upscaled rock relative permeability for viscous fingering was then used as input into the fine scale modeling. To upscale to the coarse scale model a history matching approach was applied to generate dynamic pseudos. The application of appropriate effective flow properties to heavy oil characterization improves the quality of the production forecasts, and facilitates proper sizing of facilities.