Wireline logs from three (3) wells, 1, 2 and 3 were used to quantitatively evaluate the ‘Jfield’ of the NigerDelta area. The wells had been evaluated using a combination of Gamma-ray log, Resistivity logs and Neutron – Density logs. Wireline log analysis was used in the reservoir evaluation of the ‘Jfield’; the hydrocarbon sands were delineated by the use of gamma ray, resistivity and density/neutron from which the reservoir prospectivity were determined. Well 1 has 4 reservoirs, well 2 has 4 reservoirs and well 3 has 4 reservoirs, the reservoirs are namely (A, B, C, D) .This investigation helps to identify the lithologies and recognize the hydrocarbon bearing intervals as – well as to quantify the amount/type of hydrocarbon in the reservoirs contained in wells 1, 2, 3) for further exploration and exploitation in the ‘Jfield’ of the NigerDelta. The petrophysical properties of the reservoirs analyzed include: water saturation for wells 1, 2 and 3 ranging from (0.13– 0.26) %, (0.16 – 0.37) % and (0 – 0.41) %, porosity values; (18 –23) %, (14 – 20) % and (18 – 23) %, hydrocarbon saturation for the wells are; (0.74 – 0.86) %, (0.63 – 0.84) % and (0 – 0.59) % respectively. The net pay thickness for well 1 is 39.88 metres, well 2 is 53.4 metres and well 3 is 53.9 metres. The analysis of the wells depict the presence of hydrocarbons in well 1 and well 2, with only one reservoir (D) in well 3 indicating the presence of hydrocarbon.
As Oil and gas deposits are found in the porous forma- tions in sedimentary basins, under normal conditions, the reservoir occurs at locations where the appropriate por- ous formation is at a higher elevation than the surround- ing region. The task of the interpreter is to locate such occurrences. The means of doing this is the proper inter- pretation of seismic data recorded for region of interest. As with any physical procedure of this nature, it becomes highly desirable to simulate the data collection process and to gain insight by the examination of known situa- tions . Realistic 3D geological models are then re- quired as input to reservoir simulation programs which predict the movement of rocks under various hydrocar- bon scenarios. An actual reservoir can only be developed and produced once and mistakes can be tragic and wasteful. It is essential to model the reservoir as accu- rately as possible in order to calculate the reserves and to determine the most effective way of recovering as much of the petroleum economically as possible [4-7], hence, allows for 3D visualization of the subsurface, which en- hances understanding of reservoir heterogeneities and helps to improve recovery rates, as low recovery rates stem from inefficient sweep caused by poor knowledge of inter well-scale heterogeneities .
The combination of welllog and seismic data would provide a high degree of reliability in providing insight to reservoir hydrocarbon volume which may be utilized in exploration evaluations and well bore planning  . In addition, the risk associated with finding oil and gas in subtle and complex structural/stratigraphic places would be greatly minimized because such integration will help to discriminate between poor and rich reservoirs. The knowledge of the properties and extent of a hydrocarbon reservoir are important factors in estimating the hydrocarbon in place. In the present work, 2D seismic reflection data were integrated with well logs so as to de- fine the subsurface geometry and the petrophysical parameters. This study is aimed at imaging the detail sub- surface with a view to analyzing the hydrocarbon reservoir in place which may provide an insight in hydrocar- bon evaluation.
Qualitatively the petrophysical evaluation is centered on translating geophysical responses to geological parameters, for instance, what natural radioactivity means as regard shale con- tent; how sonic velocity can be interpreted as regard shale compaction; what bulk density means in terms of mineral composition etc. The ambit of this independent study is limited to the use of geophysical welllogdata to achieve not only the lithology and fluid type of the prospect zones but also the average water saturation and the productive capabilities will be predicted. However, as relevant as log parameters are, they should not be applied without the consultation of other necessary data like drill stem test, mud logevaluation, sample shows, nearby production etc, before taking a decision to drill.
Tables 1-6 show details of results for four shale horizons from GABO wells 14 to 19 obtained from the evaluation of the logdata for depth range, thicknesses, gamma ray reading and density, and from the empirical applications used to calculate TOC and TOM respectively for the delineated horizons. Also tables 7 to 10 show results and their averages for density, TOC and TOM respectively. Figures 4 to 7 show corresponding complementary plots of histograms for the four horizons, showing the relationship between these parameters. Table 11 presents the averages of density, TOC and TOM for the four horizons, while figures 8 and 9 are plots of histogram and graph respectively of the averages of these parameters showing their relationship.
A formation is said to be overpressured when an abnormally high pore pressure greater than the hydrostatic pressure occurs at a given depth, Dickinson (1953). Overpressure is very key as it occurs worldwide in sedimentary basins where hydrocarbon is exploited and produced. Hence it is important to understand and predict the regional distribution of overpressure accurately in the Coastal Swamp Depobelt of the NigerDelta Basin, in other to minimize associated risks, ensure the safety of lives and properties, and enable adequate field development plan that would lead to the optimization of assets.
The materials available for this research are 3D seismic data and well logs suites. Litho-stratigraphic correlation was done using the available lithology log (gamma ray log) to distinguish between the two basic lithology types (i.e; sand and shale) dominant in the field according to the geology of the NigerDelta . A cut off was established from the statistics of the Gamma Ray log in order to differentiate between sands with low Gamma Ray values and shales which possess high radioactive content with corresponding high Gamma Ray values. Resistivity log was used to identify the present fluid type (i.e.; formation water and/or hydrocarbon) and the hydrocarbon type was then distinguished with neutron-density crossover.
For many scientific and economic aims, laboratory data of high precision and reliability, for both the fluids and the rocks that contain them are necessary. For the petroleum geologist and the drillers such data cannot be acquired quickly enough or cheaply enough to be useful. The operators in the oil fields needed a method by which the fundamental properties of the rocks and their fluid contents could be quickly and reliably determined in the subsurface.
Evaluation of the Tymot Field, NigerDelta basin was achieved using seismic data volume and well logs. Petrophysical analysis was carried out usinglog suites from four well. Three hydrocarbon sands at different intervals were mapped in the field. Seismic interpretation showed that the structural styles are widely spaced with faults forming structures for hydrocarbon entrapment and accumulation. The field exhibits structural features pertinent to NigerDelta basin which includes the roll over anticlines, down-to-basin faults, synthetic and antithetic faults. From the structural depth map of the three sands; yellow, red, and green colors denotes hydrocarbon zones. The sand F mapped has shown to have the highest reserves and best structure for hydrocarbon accumulation.
CONTRIBUTION TO KNOWLEDGE This work could be used as reconnaissance tool to pre-determine permeability and porosity at various depths using the empirical formulas generated. Water saturation, irreducible water saturation, porosity, permeability and hydrocarbon saturation combined could be used to give advice on possible locations to drain holes for further field development. This work could also be incorporated into a number of multi- disciplinary projects that use integrated subsurface datasets (core, 3D seismic and production data) to further characterize geology and fluid flow in hydrocarbon reservoirs.
From the results of the study observed in the site of Watuadegpillow lava, there were many damages which made during the development of the geoheritage site so that become not maintained, thus reducing the value of education and attractiveness, especially in the geological context. Evidence of damage to the geoheritage site of WatuadegPillow Lava is the construction of irrigation by the local government which is the function of irrigation development, namely for surface water channels and the availability of water for agriculture. However, the development of irrigation in the beds of pumice and tuffs of Semilir Formation around it is very influential on the geological history and geological processes that occur and take place in the area, especially as stratigraphic correlation data that are connecting the surrounding rocks.
Most of the traps in Nigerdelta fields are structural although stratigraphic traps are not uncommon. The structural traps developed during synsedimentary defor- mation of the Agbada paralic sequence [9,10]. Structural complexity increases from the north (earlier formed de- pobelts) to the south in response to increasing instability of the under-compacted, over-pressured shale. , de- scribed a variety of structural trapping elements, including those associated with simple rollover structures clay- filled channels, structures with multiple growth faults, structures with antithetic faults and collapsed crest struc- tures. On the flanks of the delta, stratigraphic traps are likely as important as structural traps. In this region, pockets of sandstone occur between diaperic structures. Towards the delta toe (base of distal slope) this alternat- ing sandstone-shale sequence gradually grades to essen- tially sandstone. The primary seal rock in the NigerDelta is the interbedded shale within the Agbada Formation. The shale provides three types of seals—clay smears along faults, interbedded sealing units against which res- ervoir sands are juxtaposed due to faulting and vertical seals. On the flanks of the delta, major erosion events of early to middle Miocene formed canyons that are now clay-filled. These clays form the top seal for some im- portant offshore field locations.
In this study, welllog derived petrophysical parameters of four (4) delineated clastic reservoirs in AK field, located onshore eastern NigerDelta have been effectively employed to characterize and assess hydrocarbon prospect potential of the field. Wireline welllogdata, such as gamma ray, resistivity log suite, Compensated Neutron Log (CNL) and Formation Density Compensated (FDC) were studied and analyzed for qualitative and quantitative evaluation of the formation units in the field. Lithologic discrimination aided the identification of sandy units, while fluid identification and discrimination defined the hydrocarbon saturated reservoir units in the field. Other derived parameters such as porosity, permeability, water saturation, hydrocarbon saturation, Net To Gross (NTG), net hydrocarbon pay, Bulk Volume Water (BVW) among others were employed to quantitatively characterize the delineated reservoir units, especially to establish their hydrocarbon potential. Four (4) sandy reservoir units, A1, A2, A3 and A4 which ranged in thickness from about 60- 350 ft were identified from four exploratory wells AK- 01, AK-02, AK-03 and AK 04 to be hydrocarbon bearing. The clastic reservoirs presented medium to relatively high formation porosity (0.27-0.38), low to average permeability value (61.6-685.5 mD) and significant to high hydrocarbon saturation (0.42-0.97). A plot of true formation resistivity values (R t ) against water saturation
intensified exploration for oil and gas accumulation reservoir rocks of NigerDelta basin. This is after a long while of non-productive search in the Cretaceous sediments of the Benue trough (Doust and Omatsola, 1990). The NigerDelta is a Cenozoic gross offlap clastic succession built out atop Anambra Basin and forming a part of the western African miogeocline that spread out onto the cooling and subsiding (Whiteman 1982, Wright et.al. 1985) oceanic crust generated as the African and South American lithospheric plates separated. It covers a 75,000 square kilometer area within the Gulf of Guinea, West Africa and is composed of an overall regressive clastic sequence which reaches a maximum thickness of 30,000ft to 40,000f (Weber and Daukoru, 1975; Evamy et al., 1978; Doust and Omatsola, 1990) (Figure 1). The interest of this work is to characterize the reservoir sands encountered by the three deep wells in the “X” field of Nigerdelta basin usingwelllogdata.
This research was conducted to evaluate the exploration potential and risk associated with producing reservoirs from Charlie Field, Onshore NigerDelta. A 3-D post-stack depth migrated seismic volume, check-shot and welllog suite from two exploratory wells (C- 001 and C-002) drilled into Charlie Field were utilized for this study. Data analysis and visualization was done using Schlumberger Petrel software. The workflow began with data loading, quality checks and log conditioning. Gamma ray log, neutron and density logs were used to delineate 10 reservoir intervals (A-J). Resistivity established the contained fluid, while neutron and density logs were used to discriminate hydrocarbon type. Reservoir A (R-A) and reservoir J (R-J) were selected for further assessment based on thickness, cleanliness and contained fluids. Average gross and net established from log signatures are 126.67ft and 123.57ft for R-A and 137.66 and 112.69ft for R-J. Effective porosity, permeability and water saturation are 29%, 2218.38 mD and 27% in R-A; and 26%, 2286.33 mD and 31% in R-J. Twenty-nine faults were identified which included antithetic and synthetic faults. Seismic ties enabled mapping R-A and R-J reservoirs as positive peak amplitude events. Generated time and depth converted structure maps revealed closures that are anticlinal supported by normal faults. Maximum amplitude extraction and OWC mapping enhanced prospects and lead identification. Three prospects and a lead were identified on Surface A, and two prospects and a lead on surface B. The maximum amplitudes showed no conformance to structure, hence there is likely tendency for sand-sand juxtaposition, which decreases the sealing capacity of the faults. Because field management decisions are usually made using a deterministic approach, hydrocarbon volumes were evaluated using a deterministic approach where minimum, mean and maximum petrophysical properties for each reservoir, were used for calculating P10, P50 and P90. Based on P50, prospect A in R-J had STOIIP of 1023 mmstb and prospect B had STOIIP of 106 mmstb. For R-A, prospect A had STOIIP off 625 mmstb, 175 for B and 176 for prospect C. Production profitability assessment done using a risk factor of 20%, onshore production cost of 31.6 USD, recovery factor of 35% for NigerDelta reservoirs, and the current price of oil at 63 USD, showed that all the prospects can be recovered at a profit. In terms decreasing profitability, the following trend was established; prospect A in R-J (2.248 billion USD), prospect A in R-A (1.373 billion USD), prospect B in R-A (474.77 million USD), prospect C in R-A (386.85 million USD) and prospect B in R-J (232.99 million USD).
This research work is aimed at using acoustic impedance as means of predicting lithology and hydrocarbon away from well control of “Ovi” Field hence providing a detailed evaluation of the hydrocarbon potential of the area. The methodology used involves identification of hydrocarbon bearing reservoirs from well logs using Gamma ray and resistivity logs, wells correlation, petrophysical analysis, well to seismic tie, horizon and fault mapping, generation of structural maps, acoustic impedance crossplot analysis and seismic inversion using model based approach. Three reservoir sand were mapped within the Agbada Formation. From the crossplot of acoustic impedance against gamma ray, porosity and water saturation, the acoustic impedance ranges from 24500-27500 (ft/s)*(g/cc) for shale and 17500-24500 (ft/s)*(g/cc) for sand based on the saturating fluids, the results also shows that acoustic impedance have a linear relationship with water saturation, while porosity have an inverse relationship with acoustic impedance for the study area. Average acoustic impedance maps for reservoir tops generated from the inverted seismic data indicated areas of low acoustic impedance corresponding to hydrocarbon bearing zones that were not detected on the time maps. The result provided detailed information about the subsurface lithology and hydrocarbon saturation away from well control of the study area.
The Lowstand Systems Tract (LST) deposits are derivatives of gravity movement due to sediments depositions by rivers as they traverse the shelf and upper slope proceeding towards the incised valleys and canyon along the continental slope (Armstrong and Braisier 2005). The Lowstand Systems Tract is characterized by interbedding of shale and sandstone that follow a coarsening upward pattern with initial progradational stacking pattern and a subsequent aggradational stacking pattern. There is shallowing upward trend of foraminiferal assemblages from regions with high foraminiferal abundance to complete barren regions. Transgressive Systems Tract (TST) identified showed an upward increase in foraminiferal abundance and diversity, it represents the well sections with the highest foraminiferal abundance and diversity often culminating in the Maximum Flooding Surfaces. The TSTs identified exhibits retrogradational geometries. These deposits are composed of sand units characterized by fining and thinning upward trends which are overlain by the Maximum Flooding Surfaces and underlain by Sequence Boundaries and Transgressive Surfaces (TS). The TST contains rich preserved microfossils. This has been reported to be due to the progressive supply of sediments in the process of transgression as turbidity current reduces leading to the high occurrences of clear water micro-fauna (Armstrong and Braisier 2005).
The identification of lithology was carried out before carrying out correlation of “reservoir” and correlation of wells, this was done as a result of the appearance of different log type and logs signature, from the “gamma ray” log, increase by the left side shows a sand unit while sharp decrease by the right side shows a shale unit from the resistivity logs. Indication given at sand unit simplify-hydrogen bearing and the intervals can be put into consideration. WellLog Correlation
(3) Depositional Model Of The D7.000 Sand From the gamma ray log of the reservoir (D7.000) sand of study; the reservoir could be divided into two sequences based on the mode of deposition. These are the upper and lower part, i.e. the transgressive and regressive sections. Consequently, they are demarcated by an uncored mudstone layer at a depth of about 12352ft in the well. However, the core gamma ray signature shows that the upper part of the lower D7.000 sand and the lower part of the upper D7.000 sand are not cored due to the muddy nature. Therefore, the reservoir model is considered along this line. The upper part which ranges in depth from 12352 to about l2l50ft, consists of the following facies associations, namely from the base; tidal deposit, amalgamated channel, tidal flat, tidal channel, and marine shale. Therefore, the model will be that of transgressive estuarine system. Some of the sedimentary structures associated with the estuarine deposits are reactivation surfaces as a result of the influence of flood and ebb currents (bipolar current) on the sedimentary deposits. Couplets of sand and shale in heterolithic sequence and sporadic trace fossil assemblages with an increase in faunal diversity upward. Furthermore, the lower regressive part of the reservoir sand of study ranges in depth from 12352 to 1252 ft. This lower part which forms a progradational sequence consists of the following facies associations starting from the base of the reservoir sand, offshore marine mud, lower shoreface and upper shoreface. The lower depositional sequence of D7.000 sand are deposits of a prograding wave dominated shallow marine shoreface setting. This interpretation is supported by the abundance of hummocky cross stratification structures, abundance of diverse marine trace fossils, and the upward decrease in diversity and population of these trace fossils. However, the two channel sandstones in the D7.000 reservoir have different geological properties and should be identified with different geological models. The tidal channel has a transgressive property, that is, it exhibits a fining upward sequence. Also, it has a gradational and erosional upper and lower contact respectively. Furthermore, in gamma ray log, it has a bell shape structure, while in the amalgamated channel of the upper retogradational sequence, it has abrupt upper and lower erosional boundaries respectively, blocky gamma ray log signature and shows little or no separation in neutron-density logs.
Permeability is the measure of connectivity of pore spaces within a rock. This was calculated by loading each individual core plug of known length and diameter into a Hassler type core holder. Then subjected to a low confining pressure of about 15-20 bars to prevent gas flow around the plug sample. Air was then allowed to flow through the sample by applying a pressure differential across the sample. After which the flow rate and pressure. Differential were measured, recorded and used to determine the sample permeability using Darcy’s equation.