Seismic driven reservoir characterization, offshore Niger Delta, Nigeria

This paper presents the subsurface characterization by applying integrated three dimensional seismic attributes analysis on a 3D seismic dataset from OPO field, within the western Niger Delta basin. The volume attributes aimed at extracting features associated with hydrocarbon presence detection, net pay evaluation and porosity estimation for optima reservoir characterization. Neural network (NN) derived chimney properties prediction attribute was used to evaluate the integrity of the delineated structural traps. Common contour binning was employed for hydrocarbon prospect evaluation, while the Seismic coloured inversion was also applied for net pay evaluation. Amplitude anomalies were used to delineate bright spots and flat spots; good reservoirs in term of their porosity models, and fluid content and contacts (GOC & OWC) were identified in the area through common contour binning, seismic colour inversion and supervised NN classification

Building 3D Lithofacies and Depositional Models Using Sequential Indicator Simulation (SISIM) Method: A Case History inWestern Niger Delta

Sequential indicator simulation algorithm is one of the popular stochastic simulation algorithms for reservoir geomodelling. It has been used to model delineated lithofacies and depofacies units within the OPO field, western Niger Delta. This simulation algorithm was chosen because of its ability to honour the well logs as local conditioning data using the global histogram, areal and vertical geological trends of the data, as well as the patterns of correlation. Three lithofacies were identified and modelled, namely sand, shaly sand and shale units. Vertical succession of the depositional facies within the field reveals five major facies which are basal shelf shale facies, heterolithic (sand–shale) facies, lower shoreface sand facies, upper shoreface sand facies and shoreface channel systems. The general environment of deposition is interpreted to be shoreline–shelf systems where the shoreface channel units, upper shoreface sand, lower shaly sand and heterolithic units constitute the parallic reservoir sequences, while the shale units within the shoreface and coastal environments act as potential source rocks and caprocks for hydrocarbon accumulation

Prospect Analysis and Hydrocarbon Reservoir Volume Estimation in an Exploration Field, Shallow Offshore Depobelt, Western Niger Delta, Nigeria

The daunting challenge in the exploration and production of oil and gas in the face of continual rise in the world’s energy consumption has long been how to economically recover bypassed reserves within existing assets. This research is focused on the analysis of prospects and volumetric estimation of the hydrocarbon reservoirs delineated within an exploratory field using 3D seismic data and suites of wireline logs. The prospectivity of the delineated reservoir was carried out using seismo-structural interpretation and formation evaluation towards the assessment of the prolific hydrocarbon occurrence within the field. The reservoirs have porosity (0.29–0.32) for H1, (0.20–0.31) for H2 and (0.30–0.40) for H3 and the average computed hydrocarbon saturation of (0.31–0.62) for H1, (0.16–0.52) for H2 and (0.64–0.73) for H3, hydrocarbon pore volume (HCPV) of 28,706.95, 33,081.2 and 45,731.49 barrels for H1, H2 and H3, respectively, while the estimated stock tank oil initially-in-place (STOIIP) range (136.8–140.73) MMSTB for H1, (36.77–489.64) MMSTB for H2 and (166.62–308.14) MMSTB for H3. The observed porosity and hydrocarbon saturation for the delineated reservoirs as well as the estimated hydrocarbon pore volume and storage total oil in place indicate that the reservoirs are highly prolific. The study has therefore contributed to the understanding of hydrocarbon resource potential within the study area

Velocity-Porosity relationship in clastic formations – a case study from some parts of Niger Delta, Nigeria

Velocity-Porosity relationship in some parts of Niger Delta was studiesd with a view to establish the velocity-porosity relationship and the generalized equation(s) that best describe this relationship in clastic formations. Five wireline logs were acquired for the study. Neutron porosity log data was converted to synthetic velocity (VTA) using time-average equation of Wyllie (1956), and the sonic porosity log was converted to sonic velocity (Vsonic). The results were presented as velocity-porosity crossplots with the trend line equations and the coefficient of correlation. The results give a distinct inverse velocity-porosity relationship; i.e. velocity decreasing with increasing porosity. The velocity-porosity relationships established from both sonic log (Vsonic) and time-average formulation are best described by polynomial fitting of 2nd order. Two generalized equations of high coefficient of correlation, which can be used to calculate compressional velocity (Vp) from porosity values in clastic formations, were established from these relationship. Keywords: porosity, velocity, compressional, polynomial and clastic Global Journal of Pure and Applied Sciences Vol. 12(1) 2006: 125-12

Hydrocarbon resource evaluation using combined petrophysical analysis and seismically derived reservoir characterization, offshore Niger Delta

Abstract Subsurface characterization and hydrocarbon resource evaluation were conducted using integrated well logs analysis and three-dimensional (3D) seismic-based reservoir characterization in an offshore field, western Niger Delta basin. Reservoir sands R1–R4 were delineated, mapped and quantitatively evaluated for petrophysical characteristics such as net-to-gross, volume of shale, water saturation, bulk water volume, porosity, permeability, fluid types and fluid contacts (GOC and OWC). The volume attributes aimed at extracting features associated with hydrocarbon presence detection, net pay evaluation and porosity estimation for optima reservoir characterization. Neural network (NN)-derived chimney properties prediction attribute was used to evaluate the integrity of the delineated structural traps. Common contour binning was employed for hydrocarbon prospect evaluation, while the seismic coloured inversion was also applied for net pay evaluation. The petrophysical properties estimations for the delineated reservoir sand units have the porosity range from 21.3 to 30.62%, hydrocarbon saturation 80.70–96.90 percentage. Estimated resistivity R t, porosity and permeability values for the delineated reservoirs favour the presence of considerable amount of hydrocarbon (oil and gas) within the reservoirs. Amplitude anomalies were equally used to delineate bright spots and flat spots; good quality reservoirs in term of their porosity models, and fluid content and contacts (GOC and OWC) were identified in the area through common contour binning, seismic colour inversion and supervised NN classification