In this study, a deterministic co-infection model of dengue virus and malaria fever is proposed. The disease free equilibrium point (DFEP) and the Basic Reproduction Number is derived using the next generation matrix method. Local and global stability of DFEP is analyzed. The result show that the DFEP is locally stable if R0dm < 1 but may not be asymptotically stable. The value of R0dm calculated is 19.70 greater than unity; this implies that dengue virus and malaria fever are endemic in the region. To identify the dominant parameter for the spread and control of the diseases and their co-infection, sensitivity analysis is investigated. From the numerical simulation, increase in the rate of recovery for co-infected individual contributes greatly in reducing dengue and malaria infections in the region. Decreasing either dengue or malaria contact rate also play a significant role in controlling the co-infection of dengue and malaria in the population. Therefore, the center for disease control and policy makers are expected to set out preventive measures in reducing the spread of both diseases and increase the approach of recovery for the co-infected individuals.

The impact of intra-reservoir faults on fluid connectivity and recoverable volumes in any reservoir depends principally on structural uncertainties (fault extent, fault throws, fault zone, fault heave, fault sealing capacities etc.) associated with the reservoir. This paper focuses on the integrated approaches used to determine block by block fluid connectivity, re-assignment of estimated hydrocarbon initially in-place volume and its associated recoverable volumes in different reservoir blocks in view of production performance and complex fault architecture in the field. In this study, we have explored the feasibility of determining fluid connectivity across reservoir blocks and their associated recoverable volumes by integrating reservoir performance (post-production data) with the reservoir structural uncertainties. Over 50 wells have been drilled in the field and their penetrations spread across the reservoirs. Pressure data were acquired across most of the blocks in the reservoir. The reservoir is sub-divided into separate blocks and it has over 25 years of production with evidence of over-production (Np &gt; Ultimate Recoveries) experienced in some of these blocks. This over-production triggered the need to integrate available data (Performance, Pressure data, Fluid Contacts, structural morphology etc.) to re-evaluate the impact of the intra reservoir faults on the estimation of the hydrocarbon in-place volume and recovery in the field. The integrated approach has aided the re-estimation and re-assignment of the associated volumes on a block by block basis thereby promoting the opportunity for a robust infill well planning and further development of the field.

Exceeding the estimated technical UR of mature fields is a valid positive risk to be considered in field development. Extending the field life of prolific fields in the Niger Delta using integrated subsurface analysis of available data is an imperative in the current "lower price for longer" oil economy. For matured reservoirs producing beyond their estimated ultimate recovery, it is necessary to demonstrate the basis on which a revision of recovery factors can be made (SPE et al., 2007). This paper examines how the seismic, geological, production data and pressure data were integrated to arrive at the most plausible reservoir understanding for the re-allocation of In-place volumes for the Tanure field in the Western Niger Delta. An integrated review of the field history was done on a well- by- well basis, taking into account the cross -sections and relative positions of both flowing and closed -in wells. The CO log data analysis showed the relative movement of the water influx in the field, helping to identify wells that had been shielded by sealing faults, explaining observed production performance. The pressure equivalence of the hitherto separate sub-blocks in the field proved that 75 of the sub-blocks on the various reservoir sand levels could be technically merged into 24 larger blocks. The average contacts for the new sub-blocks were estimated by petrophysical analysis of original contacts observed from open hole log data. The re-interpretation of 3D seismic and the fault model of the geological structure, led to the revision of Stock Tank Oil Initially In Place (STOIIP) estimates to support the production figures from the maturing field (SPE/WPC, 2001). Fluid contact analysis estimated OWCs for the resulting new blocks, confirmed by pressure data history from the field. The technical recovery limits for the affected blocks were revised based on the calculated STOIIP volumes of the new blocks.

The productivity of oil wells depends on a lot factors such as and not limited to environment of deposition, reservoir thickness, permeability, reservoir drive mechanism, drain hole length and formation damage at the near well bore region. The productivity of oil wells can also be linked to the effectiveness of the sand control method deployed in the well. Sand control methods play very important roles in safeguarding our assets, maximizing production from assets and reducing life-cycle OPEX for the well. This paper presents a comparative approach towards understanding the effect of different sand control methods on productivity of wells completed in a mature reservoir in the Niger Delta. The methodology involves the use of statistical comparison of the production performance of 4 sand control methods installed in the XYZ reservoir in the YED field. The approach considers the productivity performance, the average sand reliability index, and the intervention frequency ratio. The productivity performance of the completed conduits on XYZ reservoir shows that conduits completed with Slotted Liners showed impressive production performance as well as low sand production, while the wells completed with IGP had better production performance when compared to other sand exclusion methods. The drainage points completed with SCON showed average production performance, with high sand production averaging around 25-30 pptb for the completed conduits. The conduits that were completed with MCUGP showed below average production performance as well as high sand production. The results in this work will help provide an easy guide to sand control selection as it concerns productivity in the Niger-Delta region. It will also deepen the understanding of the performance of different sand control methods in the Niger-Delta Region.

Resource estimation is a basic statutory requirement and expectation in reservoir management. Proper resource estimation allows for robust field development planning in addition to the fact that the field resources should be correctly captured at all times in the books for audit purposes. The methods for resource estimation include the following: Volumetrics, Simulation, Material Balance modelling and Decline Curve Analysis. The method applied usually depends on several factors including the reservoir complexity and production history (brown or green reservoir). The DAZ field under review has structurally complex reservoirs with closely spaced producing wells and advanced production history. Several projects with different levels of maturation are planned for this field. These projects include work overs, implementation of field-wide gaslift and recompletions. For the completions with matured performance data, the use of Decline Curve Analysis and Material Balance fractional flow techniques for resource estimation were adequate. However, volumetrics and simulation model are the preferred techniques for the new completions and conduits with immature production performance history. The low case simulation model methodology proved inadequate as it was difficult to obtain a good well-level history match of the production data due to the structural complexity of the reservoirs, whilst still fulfilling the requirements of hydrocarbon limits both vertically and laterally. The conventional volumetrics method also was inadequate due to the proximal well spacing, dense faulting and the resultant complex flow patterns. The implication of this is that the drainage pattern becomes difficult to delineate and a conserved drainage area is purely theoretical. A hybrid method which integrates the results from a well history-matched base case simulation model with the ideals of a volumetrics evaluation (drainage area and RF from analogue reservoirs) for low case resource determination is hereby presented. Essentially, the streamlines which is indicative of flow path at the end of history match from the simulation model provides guidance on the drainage pattern and area. This guide is thereafter applied in a volumetric sense to estimate the resource that can be produced by the conduit. This alternate method incorporates all the static properties and elements of the dynamic simulation model in a qualitative sense, via the use of streamlines to guide the drainage pattern and area. It also provides for consistency in the estimation of low case and base case volumes. The result of this hybrid evaluation method realistically estimate both the in-place and recoverable volume. This volume estimation met statutory requirement of realistically reporting recoverable volume. The estimated volume was also used for reservoir management purposes.