Saturation height modelling is a critical input into 3-D based resource volume estimates. Calibrating saturation height models with in-field core data, particularly from the reservoir of interest, helps to reduce the uncertainties in reservoir saturation estimates. Due to paucity of Core data in most fields; Saturation height modelling is usually done with wireline logs only, using analytical equations. These equations sometimes do not have unique solutions with the same set of log data. The accuracy of the derived solutions is further reduced when these fits are derived without calibration to core data. Some of the log-only model-fits may also not have physical meaning even when there are good visual match with saturation profile at well points; thus failing when exported into a reservoir simulator. It is therefore pertinent to find a way of constraining the results from log-derived capillary models with fitting parameters obtained using core data from analogue fields in the absence of in-situ core data in subject field.The paper demonstrates the value in the use of analogue field core data for calibration of log-derived saturation model. ZAN field is a partially appraised field that has been identified for gas development with two well penetration that have complete suite of logs required for reliable saturation estimates and no core data. Log-based Capillary Pressure models were initially built, without any form of core calibration, with very limited success. To improve the quality of the model, capillary pressure measurements from analogue fields were used as building block for an improved capillary pressure model that was subsequently calibrated with logs from the field of interest. This resulted in an improved saturation match at well positions and also improved dynamic model initialisation.

Permeability is one of the most important parameters of reservoir rocks; it defines the capacity of rocks to transmit fluids in pore spaces. Permeability prediction is of extreme importance in deciding the field development strategy for green reservoirs. The reservoir rocks are made up of grains, cement and pore network. The pore network is made up of larger spaces, referred to as pores, which are connected by small spaces referred to as throats. The pore spaces control the amount of porosity, while the pore throats control the movement of fluids and the quantity of rock permeability. Generally, the sources of permeability measurements in green field are from core data, well test data and Nuclear Magnetic Resonance (NMR) data. However, core information, well test information and NMR information are usually very limited due to high cost of acquisition making justification usually difficult. The consequence is that we have very low ratio of cored to the total reservoirs in the Niger Delta. This paper discusses a methodology for accurately estimating permeability using analogue fields/reservoirs core data in green reservoirs. The main factors to consider in choosing a suitable analogue includes Facies classification, relative depth of the reservoirs, average porosity and histogram of the Gamma ray values between the subject and analogue reservoirs. This selection is usually an integrated effort between the teams Geologist and Petrophysicist. In this study, two fields were selected where permeability prediction was based on analogue core data. A robust Niger delta wide analogue selection process was applied first to identify the analogue field where core data exists. After selection of the analogue field, facies-wise poroperm transform was built. This poroperm transforms were then validated in one of the fields where real core measurements were available post study. This blind test with real core permeability data indicated an excellent match with analogue based permeability model. In the other field, the analogue based permeability was validated against NMR and mobility data acquired in some of the reservoirs. This workflow establishes the robustness of using existing analogue data to reduce the subsurface uncertainty and justify an integrated workflow of estimating permeability in the green field rather than acquiring a new data to support development decision.

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).

Nigeria's gas policy vision to be an attractive gas-based industrial nation implies that we need to continuously harness the abundant gas resources in the subsurface. This may imply that many more gas projects will be required to meet the country's aspirations. Pressure depletion under natural depletion in gas development are usually much more than in oil development. There may also be compression as part of maximising gas depletion which would lead to even further pressure depletion at end of life compared to oil development. It is therefore imperative to assess the impact of pressure depletion on Top Seal Integrity. Top Seal failure can lead to loss of reservoir-fluid containment with resultant uncontrolled flow of fluids (liquids or gases) from the reservoir into the seal or into the deep overburden, and then upwards due to reservoir pore pressure or buoyancy effects which may manifest as internal blowout. ZERN field is a partially appraised field that has been identified for gas development. We have a fair understanding of our reservoir response to depletion having been producing oil reservoirs for over 50years; however, gas production is somewhat new and there are no mature analogues for benchmarking in SPDC. Mohr coulomb shear failure criteria was used to assess the risk of top seal failure. A set of deterministic scenarios were built integrating information from planned start of field production to predicted end of life and incorporating realisations of rock strength parameters from ZERN field and analogue field. Three pre-production scenarios were coupled with nine post-production scenarios for each depleting reservoir. The resulting Mohr circle envelopes for the different scenarios were analysed per reservoir to arrive at best engineering judgement for de-risking top seal integrity for the ZERN field.

The maturation and development of hydrocarbons in partially appraised fields (PAFs) is often threatened by the high degree of subsurface uncertainty resulting from limited well penetration and paucity of subsurface data in such fields. The uncertainties ranges are sometimes very wide and the resultant cost of further appraisal is so prohibitive that the value and economic indices of carrying out development projects in these fields are severely eroded. For PAFs which are gas-bearing, the challenge is further underscored by the relatively lower price of natural gas and associated higher cost of infrastructure compared to oil. Thus, if not adequately managed, the subsurface uncertainties can go a long way in defining the economic success or failure of planned development projects in PAFs. For this reason, geoscientists and petroleum engineers are tasked with the responsibility of integrating and analysing all available data in the field with the aim of assessing, managing and reducing these uncertainty ranges as much as possible.The OZ field, which is discussed in this paper, is located in the Niger Delta and has a maximum of 6 well penetrations across sixteen (16) reservoirs in a predominantly gas field. Comprehensive data acquisition (electrical surveys and formation pressures and samples) from the last well drilled in the field in 2012, helped eliminate the fluid typing and contact uncertainties in most of the reservoirs.However, for the potentially largest reservoir in the field, the actual fluid contacts (Gas Oil Contact or Hydrocarbon Water Contact) were not logged rather a Gas-Down-To (GDT) and Water-Up-To (WUT) were logged in this reservoir at 100ft apart. With a 100ft column of undifferentiated fluid, the resource volumetric uncertainties varied substantially and if the entire 100 ft column contained hydrocarbon then depending on the type (gas or oil) and ratio, the planned development of the reservoir could easily change from primarily gas to an oil development with a gas-cap blowdown in the future. Hence, the fluid typing and contact delineation emerged as one of the major uncertainties associated with the development of the reservoir and the field at large. To reduce this uncertainty, systematic field reservoir pressure analysis coupled with the integration of other electrical surveys and regional knowledge were applied to significantly minimize the fluid type and contact uncertainties.This paper showcases details of the analysis and its implication in cost reduction and project value enhancement.