Huge hydrocarbon volumes in the Niger Delta are potentially screened out as non-reservoirs due to conventional net sand definition that precludes complex lithologies (silty, laminated and heavy mineral formations). The situation is usually prevalent in reservoirs with legacy logs (vintage wells without Density, Neutron, NMR, etc.). Netsand determination is one of the key uncertainties when evaluating resource volumes. This uncertainty elevates in complex lithologies especially with limited suite of logs. This report unravels the steps to adopt in selecting/ ranking input logs for net sand definition, its validation with reservoir production data (Production log), reservoir sampling (formation fluid & pressure) core data (full bore and/wall sample) drilling cutting etc. In addition, two case studies (fields with vintage and another with more recent well data set) resulting in circa 450% and 40% increase in HCIIP from a recent evaluation with application of the hierarchical process. This translated to increase in ultimate recovery and improved project economics (Net Profit Value and Uith Development Cost).

Considering the imminent end of the ‘easy oil’ era, the increasing demand for energy and the global push towards the energy transition, oil and gas companies are more than ever interested in sustainable ways to develop marginal and complex hydrocarbon fields economically, through the application of technology and maximization of data analysis. In small partially appraised fields where the cost of drilling an appraisal well could derail the project economics, it becomes necessary to sweat the limited data available for reservoir modelling. The uncertainty analysis must be robust enough to ensure that the adopted field development strategy would yield a positive net present value despite the wide uncertainties associated with the field. The conventional workflow for subsurface uncertainty modelling involves defining the uncertainty ranges of static and dynamic reservoir parameters based on a single reservoir model concept. This paper focuses on a marginal field case study where the multi scenario modelling approach was adopted. This approach considered alternate reservoir geologic concepts based on different interpretations of the reservoir architecture, taking full cognizance of the available data, reservoir uncertainties and regional geology knowledge. Field Alpha is located onshore of Niger Delta in Nigeria. The geologic setting consists mainly of multi-storey, complex channel-belt systems, incising through Shoreface deposits. The reservoir of interest is an elongated structure with only two well penetrations located at the opposite distal part of the structure. The key reservoir uncertainties are reservoir structure, architecture, connectivity, and property distribution. Two possible distinct architecture were interpreted based on regional correlation and seismic. This paper focuses on how the interpretations and other information informed a robust development strategy that yielded significant (30 %) reduction in development cost and positive net present value.

A good estimate of porosity can be derived from the density log based on the simple tool physics, if key variables such as fluid density (of the invaded zone) and matrix density are known. Sandstone dominates mineralogy in the Niger Delta area and its density is known within an acceptable uncertainty, based on abundant availability of core measurements. However, the uncertainties associated with in-situ fluid density values are more drastic (0.2 − 1.1g/cc), depending on the formation fluid density, the drilling mud density and degree of invasion. In evaluating the porosity of the formation, estimation of actual fluid density to be used, especially across light hydrocarbon zones, has always been a major source of uncertainty and different methods have evolved over the years for tackling this challenge. This paper examines some of the methods that have been used over the years and provides a simple, robust and auditable method for providing a good estimate of formation porosity that does not depend on an independent estimation of fluid density, and as such, it is not affected by the presence or otherwise of light hydrocarbons. It uses a combination of the density and neutron logs, with volume of shale calculated from the same log sets as a compensator.

Field development is heavily contingent on the proper delineation of the field's resource volume along with the subsurface uncertainties. For green fields, appraisal drilling reduces uncertainties, but has the potential of cost escalation and delays in project timelines thus making projects less competitive. This study highlights how a fast tracked appraisal/development strategy for 1.7 Tcf of gas development project worth $800mln was developed and approved by the regulatory authorities. The GATOE field under review is in the South East of the Niger delta, Nigeria. The field is 80 km2 in aerial extent. It consists of 11 stacked hydrocarbon-bearing reservoirs of varying thicknesses and, is penetrated by 5 wells. Seven (7) of these reservoirs (3 AG and 4 NAG) with GIIP of 900 Bscf that are ‘ready-to-go’ gas resource were captured in the ‘Tranche-1’ development scope. The remaining 4 reservoirs which are AG reservoirs with uncertainties in the actual oil column were grouped for trench-2 development but will be appraised during the Tranche-1 execution phase. Usually regulatory approval for field development is secured post appraisal drilling. This study however, proposes a concurrent field development and appraisal scheme where development wells (for fairly known reservoirs) are used to also appraise reservoirs with appraisal needs. Thus significantly reducing the number of appraisal wells (from 3 to 1) and ensuring the delivery of fast-tracked field development (early ‘First-gas’ date). The only appraisal well will be drilled at the tranche-1 execution stage. In order to achieve this, a multidisciplinary evaluation of all available data was done in addition to the use of reliable technology. This is with the aim of demonstrating that the fast-tracked gas development will not jeopardise the recovery of any potential oil that may be proved from the appraisal exercise. This study demonstrates the viability of a field development strategy in which ‘freezing’ of a development concept prior to full field appraisal can be achieved. The outcome is a massive reduction in appraisal costs and accelerated field development.

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.