The presence of oil rim in gas reservoirs could potentially have an impact on the timing and philosophy of gas development in the field. Sound reservoir management strategy requires investigation of the development feasibility of the oil rim as part of the field development planning study. This is also a prerequisite to securing regulatory approval for the resulting field development plan. Eleju C1000 reservoir contains a proven 10ft oil rim with a huge gascap supported by clearly logged fluid contacts. The field is located onshore Niger Delta, with six well penetrations, leading to the discovery of nine hydrocarbon-bearing sands. The field development concept is based on the gas resource in C1000 reservoir, which holds over 80% of the estimated field gas in-place volume. Based on the available geoscience and engineering data, analytical and simulation methods were employed to evaluate the feasibility of developing the 10ft oil rim in C1000 reservoir. The operator's Oil Rim Development Guidelines and Wyne et al Matrix (for evaluating oil reservoir feasible concept) were employed in selecting an optimum development concept for the C1000 reservoir. Analytical and simulation methods resulted in C1000 estimated EUR per well range of 0.3 – 0.4 MMstb with a unit development cost (UDC) of about $100/bbl excluding flowlines and facility. This is not economically favourable to the project which has a UDC of $3.4 per boe for gas development only. Therefore, the optimum development option for reservoir C1000 is gas development only.

The management of uncertainties associated with ‘green fields' remains a challenge due to data paucity. In the context of rising development costs for oil and gas projects, integration of data from all available sources becomes imperative. This integration has been demonstrated to reduce identified subsurface uncertainties and risks. Biostratigraphic data which comprises use of forams and fauna from ditch cuttings picked in several reservoirs in the field has been evaluated and is used to delineate the sequence stratigraphic boundaries which have been shown to be useful for building the framework for field correlation, thus the building of realistic static models. The CAMOY Gas field located onshore Niger Delta basin was discovered in 1961 by CAMO-1 well. To date, a total of six wells have been drilled in the field. The field is split into two fault blocks by CAMO fault (an East-west trending fault) in the south. The minor block is penetrated by just one well, with the remaining five wells in the main block. A total of nine hydrocarbon-bearing reservoirs have been penetrated occurring between the depths of 6500 ftss and 11000 ftss. Key subsurface uncertainties that impact on the development plan of the B4 gas reservoir have been identified, and they are associated with structure and stratigraphy. A range of static volumes were computed initially based on the original understanding of the underlying structural and stratigraphic uncertainties. However, by integrating biostratigraphic data in the reservoir correlation, the uncertainty associated with stratigraphy is reduced, leading to a more realistic range of volumes. Following the building of a realistic 3D model and volume ranges, two wells have been proposed to be drilled to develop the reservoir. The placement of one of the wells closer to the CAMO fault has been optimized post application of biostratigraphic data in B4 gas reservoir correlation.

While the development of retrograde gas-condensate fields is usually targeted at supplying medium to long-term contractual obligations, their profitability is significantly influenced by the ability to maximize condensate (C5+) recovery. This, however, is impacted by the retrograde condensation phenomenon where condensate drop-out in the reservoir during depletion results in loss of huge amounts of valuable liquids, which reduces the effective gas permeability and overall reservoir productivity. One of the ways to manage the impacts of this phenomenon is via Gas Recycling. Horner Field is located onshore Niger-Delta and has two prolific overpressured reservoirs, G1X and G2X. G1X reservoir is a lean gas reservoir with initial CGR of 51stb/MMscf. G2X reservoir is a near critical fluid with a CGR range of 188 to 280stb/MMscf with depth, suggesting a compositional grading system. The potential production challenge in G2X reservoir is retrograde condensation in the reservoir coupled with water encroachment. The Constant Volume Depletion (CVD) Experiment from the PVT Laboratory Study indicates maximum liquid dropout of 6% at reservoir pressure of about 2000 psia in G1X reservoir and 40% at reservoir pressure of about 4000 psia in G2X reservoir, thereby making G2X reservoir a potential candidate for enhanced condensate recovery. This paper presents overview of an assessment of the potential benefits of gas recycling in Horner Field using full compositional dynamic and integrated production models. Six development wells were found to be optimal for Horner field development. Sensitivities on injector optimum location and well counts were carried out. While the natural gas (mainly methane) from G2X reservoir was being recycled into thesame reservoir, the wells in G1X reservoir were beaned up to ensure security of gas supply obligation. 1-injector Scenario was found to be optimal with incremental condensate recovery factor of about 8%and positive economic indices of 15.2% IRR.

Field X is one of SPDC's major gas fields located onshore of Nigeria with six well penetrations and two key reservoirs, A1000X and B4000X,. The field is covered by a 1992 3D seismic reprocessed PSDM with relatively poor imaging quality. This caused uncertainties with respect to the interpretation of possible intra-reservoir fault compartmentilization. These intra-reservoir faults are on the footwall of two major southern and eastern boundary faults. To optimally develop these reservoirs, it was proposed to drill an appraisal well in the eastern fault block, modelled as a reservoir compartment, and subsequently carry out an interference test to establish the lateral hydraulic connectivity of the reservoirs. A new seismic data was acquired and processed to resolve the uncertainties associated with the poor imaging quality of the 1992 seismic. The interpretation of the new seismic showed similar structural trend, albeit with better clarity of the subsurface images in the fault shadow zones.  It also showed continuous seismic reflection loops suggesting a more better lateral reservoir connectivity To better understand the reservoir lateral hydraulic continuity, a multidisciplinary integrated study was conducted using all available data (production tests, Seismic and Petrophysical data). This paper covers the multi- disciplinary work carried out to establish the lateral connectivity of the reservoirs and its significant cost reduction to the total project cost.