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.
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.
Uncertainty management for resource volume of a brown field is relevant. An analytical approach via dynamic model was used to evaluate this impact on a developed gas reservoir (brown) by two other reservoirs. One of them is a green oil-rim reservoir, while the other is a developed oil reservoir. This is due to sand-to-sand juxtaposition with the two reservoirs. Integration of available data over time, while considering all the reservoir uncertainties was adopted. This was buttressed by the continuous production from the gas reservoir, that had already gone past the initially evaluated Gas Initially in Place (GIIP). The brown reservoir is a highly faulted gas reservoir with twenty-seven (27) years production history, by seven wells. The reservoir's GIIP re-evaluation had been done twice over the years. This was because it had fully developed its ultimate recovery, with three wells still producing. This GIIP re-evaluation approach could no longer be utilized, as it had very good well coverage. Fault seal analysis, pressure, PVT sample and log data taken over time reveal the likelihood of communication across the stacked reservoirs. A multi-tank material balance model (MBAL) was built via a multidisciplinary approach. The model was history matched using an experimental design approach that saved time and contacts were calibrated. The result showed the quantity of hydrocarbon in both reservoirs that have flowed into the developed gas reservoir. This provides a snapshot on the resource volume impact of the reservoirs with respect to their development and uncertainty management. Revised development plans and resource booking for the reservoirs are also study outcomes. This is relevant for business decisions on resource volume booking and reservoir management. This approach is a quick win within the Well, Reservoir and Facility Management (WRFM) workspace. Further work by building a 3D simulation model and pressure data acquisition is required for robust benchmarking.
Interpretation of reservoir boundary conditions and well drainage areas have been historically done conventionally; using analytical and numerical simulation approaches with constant pressure, no flow, leaky and conductive boundaries. This paper investigated the effect of Gas Water Contact (GWC) boundary on the pressure transient behavior. The novel approach adopted involves building numerical simulation well test models that investigate the effect of using Carter Tracy analytical aquifer model to simulate the response at the aquifer interface of a gas reservoir using SAPHIRE software. Bourdarot1 and Kuchuk2 stated that the effect of an aquifer can be modeled with a constant pressure boundary model. This model assumes that the pressure at the boundary of the reservoir consistently remains at the initial reservoir pressure during the drawdown and build up phases of the well test. Hence, it suggests that the pressure support from gas cap is very strong due to expansion and that the multi phase flow effects can be neglected. These assumptions work well for gas cap depletion systems. However, in the case of a water drive system, they may be incorrect. The result of this investigation indicates that pressure transient at Gas Water Contact boundary behaves like a constant pressure boundary for gas reservoir with small sized aquifer or a radial composite system for gas reservoir with large or infinite aquifer respectively. The former is due to the change in fluid diffusivity and very high mobility contrast. (Khμ)1→(Khμ)2 (with 2>>1) coupled with expansion of active gas cap while the later is due to mobility contrast coupled with expansion from the active water influx. The result of this investigation was compared with the conventional analytical method of using a constant pressure boundary assumption. It is recommended to apply the results of this investigation in: (i) estimating the Gas Water Contact in a down-dip reservoir and therefore help in the quantification of reservoir volumes to support existing reliable technology for determining the Lowest Known Hydrocarbon (LKH) in a Gas Down To (GDT) scenario by applying shrinking box technique to a recognized onset of constant pressure or radial composite effect in a DST or multi rate test in a down dip gas well (ii) Analytical Aquifer boundary modeling in well test designs as it affects drainage area and volume.
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