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.

The maturation and development of gas resources has of recent been on the front burner for many Oil & Gas producing countries and companies, mainly due to the drive for more environment friendly fuel and increasing demand for natural gas as a key driver for industrialization and growth. In Nigeria, the situation is not different, with proven reserves of 180 Tcf, but very low figures in production and utilisation of its gas resources, there has been an increased focus and push towards increased development in the natural gas sector. From the inception of oil and gas exploration in the late 1950’s to late 1990’s, most of the focus in the Nigerian Oil and Gas industry has been towards oil development, with little or no focus on gas, which led to the suspension of many exploratory/appraisal gas discoveries in several fields, with no plans of further development. The Zeta field is located in the Niger Delta region of Nigeria, with predominantly gas bearing reservoirs. Together with other nearby fields, it has about 9 Tcf of discovered GIIP. There is no existing infrastructure to process or evacuate the gas. Zeta field currently has four exploration and appraisal wells drilled between 1973 and 1987 and encountered 13 stacked reservoirs with a total expectation GIIP of about 2 Tcf and CIIP of about 100 MMstb. This paper highlights how opportunities in the gas sector has been maximized by deploying an innovative commercial and technical solution to unlock gas resources from a cluster of fields with large gas resource but not close to any evacuation facility. It shows how the existing exploration/appraisal wells has been planned for re-entry and side-track, to ensure a fast-tracked development of five Ready-To-Go (with no technically exploitable oil rim) reservoirs in the field. It also highlights how scalable reservoir models have been used in the development of the five reservoirs ensuring that the target onstream date is met.

In planning the development of a gas field, the gas properties play a critical role in estimating the economic value of the gas development. Chief amongst these gas properties are the Condensate-Gas Ratio (CGR) and the gas formation volume factor (Bg). While the gas volumes to be developed at standard conditions are dependent on the gas formation volume factor (or the expansion factor), the CGR determines the volume of associated condensate that can be produced and sold. A good understanding of these properties is therefore required for the evaluation of any gas field development. Fluid properties, ideally, are determined from laboratory PVT experiments carried out on fluid samples acquired from the field. These experimental PVT data are vital, especially in green fields where there is no production data that can be used to estimate some of these properties. Where such good quality experimental data are not available, it poses a major uncertainty around the fluid properties, particularly in a green field. The Dex field, a green field which is predominantly gas-bearing, has been penetrated by six wells, and fluid (PVT) samples were acquired from the last appraisal well drilled in the field. However, besides compositional analyses, extensive laboratory analyses could not be carried out on these samples due to the high level of mud contamination. While the compositional data provided some qualitative data and information on the fluid, the fluid properties essentially remained uncertain. This paper describes how this uncertainty was managed and how a reliable range of fluid properties was generated for use in the Dex gas development evaluation.