The application of chromatographic gas ratio analysis in reservoir fluid evaluation of “Beta” field in the Congo basin

This study assessed the hydrocarbon generation potentials/timing of the Awgu source rock horizons encountered in Igbariam-1, Iji-1 and Ajire-1 wells drilled in the southern Benue Trough; using one-dimensional (1D) Genesis Zetaware basin modelling software. This software enabled the integration of burial and thermal influences on Awgu source rocks with kinetic parameters. Thermal and burial history models indicate that the Awgu source horizons encountered at 3249m in Igbariam-1 well (northern part of the basin), expelled 85mg/gtoc of oil and 12 mg/gtoc of gas and hydrocarbon generation began in early Eocene with maximum expulsion in the mid-Eocene (52my) at the rate of 7mg/gtoc/my. To the south of the basin, the Awgu source horizons were encountered at greater depths in Iji-1 and Ajire-1 wells and hydrocarbon generation began in the mid-Palaeocene and peaked in the late Palaeocene (58my) at the rate of 32–38mg/gtoc/my. This resulted in an increase in generated hydrocarbon volume to the south due to (a) increased burial depth and early maturation, and (b) changing source lithofacies -more marine. The fault system linking potential reservoirs such as the Agbani sandstone and the overlying Owelli sandstone to the source rock suggests a possible migration of the generated hydrocarbons to those reservoirs at that time.     

The effect of diagenesis on reservoir quality of Mamu Sandstone,Anambra basin,Nigeria

The petrography and powder diffraction analyses were integrated to study the effect of diagenesis on the reservoir quality of the Mamu Sandstone in areas around Enugu, southeastern Nigeria. The sands are moderately to well sorted, very fine to fine grained feldspathic arenite deposited in diverse environments of upper to lower shoreface and sub-environments of delta plain. Pressure solutions, authigenic clays and quartz and feldspar overgrowths are the main diagenetic features of the sandstones in the area. These diagenetic features result in mechanical and chemical compaction, alteration of framework grains and precipitation of dissolved grains. In varying degrees, coating of clasts and filling of pore-spaces by clay and heavy minerals reduced the pore throat diameter, which caused mild reduction of the porosity and permeability of sands. Despite these observed diagenetic effects, the Mamu sands still have the potential to serve as good hydrocarbons reservoir especially for gas.     

Hydrocarbon volume optimization using improved net-to-gross estimates through core-log calibration of the “Akar field,” Niger Delta

Net to gross (NTG) is an important parameter in evaluating the volumes of hydrocarbon in place (VHIP) in reservoirs, and proper evaluation of this parameter will lead to significant accuracy in the estimated reserves. The use of conventional petrophysical log evaluations often does not provide sufficient resolution for net sand analysis of reservoirs, especially in laminated reservoir rocks. The uncertainties associated with log-derived net-to-gross estimates arise from the petrophysical shale volume (V _sh) cutoffs used in deriving the net sand count over a reservoir interval. One way of improving the net-to-gross estimates is by using a model that calibrates log-derived net to gross to a core equivalent, which is the more accurate representation of net sand counts. In this study, a model for calibrating log-derived net to gross to a core equivalent based on genetic units and facies associations of reservoir rocks in three wells (wells 7, 36, and K008) was established. Ultraviolet core photographs show a good contrast between hydrocarbon-stained sandstones and shales, and combining it with white light-slabbed core images facilitated a manual net sand count of the core photographs on a bed-by-bed basis. Petrophysical shale volume (V _sh) cutoff derived from two volumes of shale indicators was applied to generate net sand counts, which were used to get log-derived net-to-gross values. Then, the net to gross from core images and petrophysical clay volume (V _sh) analysis were compared by facies associations, and this comparison yielded a reliable core-calibrated net-to-gross model, which reduces the uncertainties in net-to-gross values estimated from V _sh cutoffs. The results show that for the distributary channel sands, net to gross derived using V _sh cutoff results in an underestimation of net to gross by about 6–10 % when compared with the core-calibrated net to gross, while for the upper shoreface units, V _sh cutoff overestimates net to gross by about 7–10 % when compared to its core-calibrated equivalent.     

Fold crest degradation and slump deposition in the deepwater Niger Delta,Nigeria

This study uses 3D seismic reflection dataset to investigate the time-integrated growth and degradation of fault-propagation folds and associated slump deposits in the deepwater Niger Delta. The results of the analysis showed that slump deposits are sourced almost entirely from the degradation of growing fold crests—resulting in the development of seaward-facing scarps on the forelimbs of these folds. The scarps develop parallel to fold axes and have dips that range between 4° SW and 20° SW. The constant presence of fan-shaped slump deposits downdip of these scarps suggests a direct relationship to fold crest degradation. Moreover, the spatio-temporal distribution of the slumps also shows a direct relationship with the heights of seabed scarps along the strike of growing folds. Slumps have short run-out distances (generally less than 5 km); however, they also travel long distances downslope (up to 10 km) across growing structures by exploiting relay areas between growing scarps.     

Impact assessment of drilling waste generated in “Eden Field” offshore,Niger Delta,Nigeria

An assessment was carried out on the pollution impact potentials of drilling waste generated from wells X and Y in “Eden Field,” offshore Niger Delta. Eleven samples each were collected from well X (8 treated and 3 untreated cuttings) and well Y (6 treated cuttings and 5 spent muds). The samples were subjected to three separate analyses, namely, oil-on-cutting analysis using Dean and Stark reflux method, heavy metal analysis using atomic absorption spectrophotometer (Unicam 929), and toxicity test analysis using bioassay procedure on test organisms such as Desmoscaris trispinosa and Palaemonetes africanus all in attempt to detect their pollution potential. The results showed that the oil-on-cutting analysis for the well X samples was between 15.8 and 17.5 % for unwashed cuttings and between 4.6 and 5.1 % for washed cuttings, while that for well Y samples was between 3.49 and 4.27 % for washed cuttings and 1.69 to 2.59 % for the drill mud samples. The heavy metal analysis on the wells X and Y samples showed absence of mercury, cadmium concentration ranged from 0.52 to 0.99 mg/kg for well X and from 0.69 to 0.78 mg/kg for well Y samples. The result of the toxicity test of samples from well X on D. trispinosa showed that 96-h LC₅₀ occurred at 9800 to 10,900 mg/l for the washed drill cutting and 6200 to 6700 mg/l for the unwashed drill cuttings. On the other hand, the toxicity test on P. africanus indicated more resistant to the toxicity of the drill cuttings as 96-h LC₅₀ was achieved at higher concentrations. At 96-h exposure, the concentration that killed 50 % of the test organism (LC₅₀) occurred at 14,000 to 16,900 mg/l for the washed cuttings and 10,300 to 11,350 mg/l for the unwashed cuttings. Similarly, the 96-h LC₅₀ was achieved on washed drill cuttings from well Y at concentrations of 9800 to 10,400 mg/l using D. tripinosa and 11,600 to 17,200 mg/l using P. africanus. The study has shown that oil-on-cutting content, heavy metal concentrations, and toxicity level did not indicate any major risk to the environment as the treatment and cleaning of the drilling wastes on the rig helped in reducing the concentration of all the contaminants in compliance with the regulatory limits.     

A study of hydrocarbon generation and expulsion of the Nkporo Shales in Anambra Basin,Nigeria

This study is a contribution to our understanding of the hydrocarbon potentials of the Nkporo Shale in the Anambra Basin, Nigeria. The main objective was to simulate the hydrocarbon generation and expulsion in the Nkporo source horizons encountered in Igbariam-1, Iji-1, and Ajire-1 wells drilled in the basin, using the one-dimensional Genesis Zetaware basin modeling software. This software enabled the integration of burial and thermal influences on Nkporo source rocks with kinetic parameters, in order to define the timing of hydrocarbon generation and expulsion in relation to the main structural episodes in the basin. The Nkporo source horizons encountered in Igbariam-1 well (2,650 m) has not expelled hydrocarbons but has a remaining potential of 380 mg/gTOC. Conversely, in Iji-1 well (3,450 m) and Ajire-1 well (3,250 m), the Nkporo source rocks expelled oil of about 110–127 mg/gTOC and gas of about 85–125 mg/gTOC. The time of expulsion was in Eocene–Oligocene (51–30 My) at the rate of 10.5–11.5 mg/gTOC/My. The remaining potentials for Nkporo source rocks in Iji-1 and Ajire-1 wells are 160 and 125 mg/gTOC, respectively. The result shows an increasing trend in maturation, generation, and expulsion of hydrocarbons with increasing depth towards the southwestern part of the basin. This resulted in an increase in the generated hydrocarbon volumes to the south due to (a) increased burial depth and early maturation and (b) changing source lithofacies—more marine. The fault system linking potential reservoirs such as Owelli Sandstone to the source rock suggests a possible migration of the generated hydrocarbons to those reservoirs at that time.     

Identification and petrophysical evaluation of thinly bedded low-resistivity pay reservoir in the Niger Delta

Arabian Journal of Geosciences - This study is on evaluation of the thinly bedded reservoirs in the Niger Delta. These reservoirs are thin laminations of sand and shale which contain hydrocarbons....     

Evaluation of the extent of pollution of discharged oil field brine in the Bonny estuary,Niger Delta,Nigeria

This is an assessment of the degree of effects of discharged produced water in river and sediments of the Bonny estuary, Niger Delta. It involved seasonal analyses of twenty-two (22) water and thirty-four (34) sediment samples from the Bonny River. The physicochemical properties (i.e., hydrocarbon content, heavy metals, and other inorganic constituents) of the water samples were examined, while the sediments were inspected for heavy metals and organic hydrocarbon constituents that may have been sourced from the discharged produced water. In addition, the principal component and cluster analyses, index of geoaccumulation, and pollution load index plots were utilized to deduce the degree of pollution, source, and distribution of these contaminants. From the results of the analyses, the Bonny seawater is contaminated with nitrate, phosphates, nickel, ammonia, and phenols in dry season, whereas nitrate, sulfate, phosphate, total nitrogen, total petroleum hydrocarbon (TPH), and heavy metals—zinc and lead—are observed in the rainy (wet) season. Similarly, the sediments are contaminated with benzene, toluene, ethyl benzene, xylene, polycyclic aromatic hydrocarbon, TPH, phenols, and heavy metals in both seasons. Considering the outcomes of these analyses, it is evident that the composition and quality of seawater and sediments of the Bonny estuary have been strongly influenced by produced water discharges in the area.     

Sedimentary facies analysis and seismic interpretation of deep-water reservoirs, “PAC” field,offshore depobelt,Niger Delta basin

A high-resolution study involving the integration of cores, wireline logs and reflection seismic dataset was used to unravel the facies assemblages, reservoir quality and hydrocarbon potential of E1 and H9 reservoirs in the “PAC” field, Offshore Niger Delta. Facies analysis of the cored PAC-14 well shows six lithofacies: massive mudstone, parallel-laminated mudstones with sideritic bands, fine-grained parallel-laminated sandstone, medium-grained parallel-laminated sandstone, fine-grained ripple laminated sandstone, and coarse massive sandstone. These lithofacies were grouped into five facies associations: channel story axis (CSA), channel story margin (CSM), inter-channel thin beds (ICTB), mud-rich thin beds (MRTB) and injectites (INJ). These facies associations are typical of a confined channel and basin floor fan deposit of a deep-water turbidite depositional environment. Reservoir unit E1 was dominated by the facies association CSA while the H9 reservoir consists mainly of the facies associations MRTB and INJ. The observed sand injectites are suggested to have formed due to overloading of compacted sands leading to upward remobilization of sand into the overlying shale. Seismic horizons and faults were mapped to understand the structures, trend and reflections within the study area. Results from petrophysical volumetrics estimated the net hydrocarbon pore volume for the E1 and H9 reservoirs as 456 MMBBL and 378 MMBBL, respectively. Exploration for deep-water reservoir mainly targets high amplitude and bright seismic reflectors and ignores the low amplitude reflectors (dim loops) which are typically interpreted as non-reservoir units. However, this study shows a low-amplitude reflector containing medium-grained sand injectite unit, which has high porosity (31.7%) and permeability (4472 mD) values, and contains recoverable hydrocarbon.