TX 75083-3836, U.S.A., fax 01-972-952-9435. AbstractPetroleum resources represent a significant part of a company's upstream assets and are the foundation of its current and future upstream activities. Often times, at the discovery of a new field or extension of an existing field, there are uncertainties associated with quantifying the amount of hydrocarbons in place. These uncertainties may be related to the structure, aerial extent of the accumulation, unseen fluid contacts to delineate the vertical extent, internal architecture of the reservoir and the characteristics of the resident fluid(s). In some cases, companies may complete and produce discovery wells before they can fully appraise the structure or may be forced by other considerations such as community disturbances to abandon appraisal drilling and continue to produce from existing well(s). All these and much more, have an impact on the evaluation of in-place hydrocarbon resources and consequently recoverable hydrocarbons. In Field Development Planning, it is routine to identify and quantify the impact of major subsurface uncertainties such as the in-place volumes and their distribution. This paper presents the methodology and results of an integrated disciplinary effort at translating uncertainties into a range of static (in-place) volumes for the purpose of field development. Erratic sand development, paucity of biostratigraphic control coupled with a complex structure make the G1.0 complex of the EGBM field one of the least understood hydrocarbon reservoirs of the Northern depobelt -Onshore, Niger Delta, Nigeria. Lack of PVT samples and analyses also add to the uncertainty in fluid properties. The erratic distribution of the petrophysical parameters especially from the G sand core also contributes to the petrophysical uncertainties.The construction of 3-D static reservoir models based on the understanding of facies and their relationships, through the integration of all available data have been used to enhance the understanding and quantification of the uncertainties. Standard evaluation of uncertainties in the spread of petrophysical parameters like porosity, hydrocarbon saturation and Net-to-Gross ratio was carried out and compared with the multiscenario concepts incorporated in the geological models. PVT parameters were derived for the reservoir based on analogy and correlations constrained with production and test data. Efforts were also made to comply with definitions of proved reserves by Securities and Exchange Commission (SEC) while still evaluating expectation volumes for internal purposes. An attempt has also been made in comparing results from the probabilistic volumetric evaluation of this reservoir and the deterministic (best estimate) method.

TX 75083-3836, U.S.A., fax 01-972-952-9435. AbstractPetroleum resources represent a significant part of a company's upstream assets and are the foundation of its current and future upstream activities. Often times, at the discovery of a new field or extension of an existing field, there are uncertainties associated with quantifying the amount of hydrocarbons in place. These uncertainties may be related to the structure, aerial extent of the accumulation, unseen fluid contacts to delineate the vertical extent, internal architecture of the reservoir and the characteristics of the resident fluid(s). In some cases, companies may complete and produce discovery wells before they can fully appraise the structure or may be forced by other considerations such as community disturbances to abandon appraisal drilling and continue to produce from existing well(s). All these and much more, have an impact on the evaluation of in-place hydrocarbon resources and consequently recoverable hydrocarbons. In Field Development Planning, it is routine to identify and quantify the impact of major subsurface uncertainties such as the in-place volumes and their distribution. This paper presents the methodology and results of an integrated disciplinary effort at translating uncertainties into a range of static (in-place) volumes for the purpose of field development. Erratic sand development, paucity of biostratigraphic control coupled with a complex structure make the G1.0 complex of the EGBM field one of the least understood hydrocarbon reservoirs of the Northern depobelt -Onshore, Niger Delta, Nigeria. Lack of PVT samples and analyses also add to the uncertainty in fluid properties. The erratic distribution of the petrophysical parameters especially from the G sand core also contributes to the petrophysical uncertainties.The construction of 3-D static reservoir models based on the understanding of facies and their relationships, through the integration of all available data have been used to enhance the understanding and quantification of the uncertainties. Standard evaluation of uncertainties in the spread of petrophysical parameters like porosity, hydrocarbon saturation and Net-to-Gross ratio was carried out and compared with the multiscenario concepts incorporated in the geological models. PVT parameters were derived for the reservoir based on analogy and correlations constrained with production and test data. Efforts were also made to comply with definitions of proved reserves by Securities and Exchange Commission (SEC) while still evaluating expectation volumes for internal purposes. An attempt has also been made in comparing results from the probabilistic volumetric evaluation of this reservoir and the deterministic (best estimate) method.

Determining reservoir porosity from density logs is possibly the most common practice in the industry over the years. Computation of porosity from density is largely affected by the grain density and fluid density used in the models. There are many best practices available in the industry to compute the grain density and fluid density with reasonable certainty. There are also many different models available which takes into account other available log responses like neutron porosity, resistivity, and shale volume to account for the uncertainties in the porosity computation. However, one of the areas that need some special attention is to integrate non-petrophysical data like seismic which can help reducing the porosity uncertainty significantly especially when no other calibration reference is available. Log measurements from the padded tools like density, neutron porosity are generally quality checked against caliper and other lithology indicators like gamma ray, resistivity, sonic etc. This paper demonstrates that porosity computation could also go wrong in a true gauge hole where density log reading apparently looks good and also showing right kind of deflection for changes in lithology. The situation can get quite complicated if the reservoir is highly over pressured and if there is no core data or regional data available. In a deep, over pressured reservoir in the niger delta, with only two well penetrations, no core measurements, and no regional calibration reference, top quality recent 3D seismic data was integrated with the well data to mitigate uncertainties in reservoir porosity. The formation evaluation challenge was that log in one of the wells showed a relatively low density reading (hence high porosity) compared to the second well density over the same reservoir. However seismic amplitude did not support the porosity variation between the two wells hence leading to further investigation on identification and management of the observed uncertainties. This paper showcased in details how the seismic data was used to identify the wrong well log reading that lead to wrong prediction of porosity distribution and the accuracy of the integrated seismic and well log predicted properties when compared to actual well log result from a well that was later drilled in the same reservoir.

Cased-Hole logging is carried out to understand post-production well saturation profiles, and subsequently, to infer the reservoir fluid distribution, especially when multiple wells dispersed across the reservoir is logged. This process promotes further oil and gas development (proper well placement). It is also used for reserves booking and production optimisation from the existing completions. The concept can also be used to conduct saturation monitoring on a routine basis to observe wells and to ensure that field statuses adhere to the Wells and Reservoir Management (WRM) minimum standards and to proper reservoir management practices. Effective strategic mapping of reservoir fluid distribution using post-production saturation logs, either from open hole and/or cased hole data has led to an improved understanding of reservoir fluid dynamics in Shallow offshore field of Niger Delta. Saturation logs have been used to update the dynamic models in the field. The general direction of water ingress in the reservoirs can now be predicted; hence the need for saturation logging is only carried out on an exception-basis. In accordance with Exception-Based Surveillance (EBS) concept, data should be acquired on a ‘need only basis’. This is a departure from the traditional routine acquisition. According to the EBS concept, the main issue is to determine when data gathering is needed. Clearly, data requirements will differ from reservoir to reservoir or from well to well. This also underscores the view that data acquisition on a routine basis may not address some specific reservoir/well peculiarities. The focus of this paper is to describe how the proposed saturation monitoring process, can be managed via EBS for a Shallow offshore field of Niger Delta, using five monitoring wells.