Geology

3d Seismic Interpretation And Petrophysical Evaluation Of Stroh-Field Onshore Niger Delta

2017-06-11T23:54:14Z

3d Seismic Interpretation And Petrophysical Evaluation Of Stroh-Field Onshore Niger Delta Aroh, Nnadozie Stephen Petrophysical evaluation and 3D seismic interpretation were carried out on the hydrocarbon bearing reservoirs of Stroh field with the aim of maximizing the benefits of petrophysical evaluation and structural interpretation in the production and development of hydrocarbon in the reservoir of the ‘Stroh field’ in Niger Delta. Eight hydrocarbon bearing reservoirs – sands ST1, ST3, ST6, ST7, ST8, ST11, ST13 and ST14 were identified from well logs and correlated across six Stroh wells. Sand ST11 was missing in Stroh-5 which crossed a normal fault. Fluid types were determined from the well log signatures; neutron density crossplot was used to check for the presence of gas. All the hydrocarbon bearing reservoirs were inferred to be oil with sand ST11 having a gas cap. Stroh-1 well saw 134.5 ft of oil in 7 sands and 26 ft of gas in 1 sand. Stroh-3st has 25.6ft of oil in one sand. Stroh-4 encountered 113ft of oil in 3 sands and 18ft of gas in one sand. Stroh-5 has 100ft of oil in 2 sands and 19ft of oil in Stroh-6. Result from petrophysical analysis shows that porosity ranges from 15.8% to 28.3%, volume of shale from 2.5% to 38.9% and permeability which increases with porosity ranges from <10md to >10000md. Bulk volume of water shows possible variation of grain size. Top depth structure maps were produced from seismic interpretation for Sands ST6, ST11 and ST13having total (47.23mmbo & 32,319.05mmscf) of oil and gas respectively. One prospects – NE (7.9mmbo low case, 10.81mmbo mid case and 12.03mmbo high case) was also identified for future drilling considerations. The result of seismic data interpretation shows that ten faults were identified F1 to F10 with two main regional bounding faults; F1 synthetic& F2 antithetic faults trending E-W. Trapping mechanisms are fault assisted and fault dependent. Time maps generated and depth converted to show structural variation and fluid contacts. The results of petrophysical analysis of the reservoir properties (NTG,Porosity,Sw) and seismic data interpretation (GRV) showed a perforation interval for ST13 as having the most profilic reservoir with a reserve of 25.28 mmbo, while ST6 has least prolific reservoir with reserve of 8.68 mmbo which serves as a guide for robust future development strategy for the Stroh field.

Prediction of Reservoir Quality Continuity and Gross Depositional Environment Within The H-Sand Reservoirs in Parts of the Xin Field, Niger Delta Basin

2017-06-11T23:54:22Z

Prediction of Reservoir Quality Continuity and Gross Depositional Environment Within The H-Sand Reservoirs in Parts of the Xin Field, Niger Delta Basin Okeugo, Chukwudike Gabriel The search for more hydrocarbons in some old fields in the onshore and shelf parts of the Niger Delta Basin is gradually becoming a major avenue for increasing the nation’s reserves. Some asset teams now have new mandates to re-evaluate key hydrocarbon reservoirs in such fields for effective optimization and production. The major reason for the re-evaluation is that some of the reservoirs between the Late Eocene and Early Oligocene (34.0 Ma and 31.3 Ma) were wrongly tagged and mapped due to little understanding of the reservoir heterogeneity and distribution and these have caused several exploration failures including loss of man hours. To remedy this situation, integrated geological and geophysical techniques were applied to map ‘H-sands’ presence, continuity, quality, and their Gross Depositional Environment (GDE) across drilled and undrilled sections of the Late Eocene to Early Oligocene sequences in the chosen field. The specific objectives of the study were to: (i) establish a detailed sequence stratigraphic and seismic facies framework for the identification and correlation of important geological time surfaces across Northeast – Southwest (dip) direction for easy understanding of H-sand distributions and geological conditions that gave rise to their deposition (ii) use a rock physics diagnostic template (RTP) approach and multi-regression relationships from elastic properties to predict the effect of depositional and diagenetic trends on ‘H-sands’ distribution (iii) apply seismic simultaneous inversion techniques in mapping accurately the spatial and lateral distribution of the ‘H–sand’ reservoirs across the field and (iv) establish Gross Depositional Environment (GDE) and sand distribution models, using integrated approaches to reduce further exploration risks. This study adopted sequence stratigraphic, seismic facies, elastic attributes crossplot and seismic inversion techniques. Well logs, biostratigraphic/biofacies data, and 3-D Pre-stack time migration seismic data were quality checked (QC) before using them to build models for quantitative and qualitative delineation, correlation and prediction of temporal distributions of the ‘H-sand’ successions between 34.4 Ma and 31.3 Ma in the XIN Field. The results of the sequence stratigraphic correlation revealed the occurrence of three (3) regional markers as Maximum Flooding Surface (31.3_MFS, 33.0_MFS and 34.4_MFS) and two (2) Sequence Boundaries (32.4_SB and 33.3_SB) across the field. Seismic facies analysis across the objective interval revealed that the geological source of the H-sands were sourced from feeder and amalgamated channel systems. These channel systems and their associated deposits show that porosity values range from excellent to good quality though the intervals in OGU-002 well was not duly tagged. Analysis of the rock physics crossplot in velocity – porosity domains confirmed that the H1000 sands of the AS_N001 well possess common increase in grains that are non-cemented with good grain-to-grain contacts and sorting which showed that the H1000 sands are connected in both time and space with the sands of the OGU-002 well. Generally, these sediments are observed to be depositionally and diagenetically controlled. The results show that sediments with depositional control possess porosity values above 22%, while sediments with diagenetic control possess lower porosity values. On the other hand, log and seismic inversion results confirmed that Lithology Impedance (LI) attribute had similar or better discriminative strength when compared with the Gamma Ray attributes. An analysis of Lithology Impedance results from log and simultaneous inversion showed that values greater than -100 ft/s*g/cc represent shale facies while values less than -500 ft/s*g/cc represent sand facies. The heterolithic lithofacies comprising of sandy-shale and shaly-sand units were found to possess Lithology Impedance values between -100 ft/s*g/cc to -500 ft/s*g/cc. The result of the crossplot analysis between Lithology Impedance and porosity confirmed that the reservoir quality of the ‘H-sand’ increases with decreasing Lithology Impedance and increasing porosity. The gross depositional environment (GDE) of the ‘H-sand’ between 34.4Ma and 31.3Ma showed shoreface (inner shelf) through proximal to intermediate offshore (outer shelf) environments. Additionally, this study has demonstrated that techniques used in this study serve to minimize uncertainties during new search for bypassed hydrocarbons in already producing fields and can be used to more accurately determine the location of new wells during infill drilling for optimum production from the field.

Geothermal Gradients and Burial History Modelling In Parts of the Eastern Niger Delta, Nigeria

2017-06-11T23:54:22Z

Geothermal Gradients and Burial History Modelling In Parts of the Eastern Niger Delta, Nigeria Odumodu, Chukwuemeka Frank Raluchukwu Reservoir and bottom hole temperatures from seventy wells in the Eastern Niger Delta suggests that two leg dogleg geothermal patterns characterize the geothermal gradients pattern of the Central Swamp and the Coastal Swamp in contrast to the single gradient patterns seen in the Shallow Offshore. In the shallow/continental sections in the Niger Delta, geothermal gradients vary between 10 - 18 o C/Km onshore, increasing to about 24 o C/Km seawards. In the deeper (marine/parallic) section, geothermal gradients vary between 18 – 45 oC/Km. The average geothermal gradient for the various depobelts is 19 oC/Km for the Central Swamp, 17oC/Km for the Coastal Swamp and 20oC/Km for the Shallow Offshore. Geothermal gradients in the Eastern Niger delta increase eastwards, northwards and seawards from the Coastal Swamp. Vertically, thermal gradients in the Niger Delta show a continuous and non-linear relationship with depth, increasing with diminishing sand percentages. As sand percentages decrease eastwards and seawards, thermal gradient increases. Thermal conductivies also decreases with depth from about 2.3 W/mK in the continental sands to 1.56 W/mK in the parallic and continuous shaly sections. Isothermals constructed at three depth levels: 1000m, 2000m, and 3000m shows that depressed temperatures occur in the western and north central parts and elevated temperatures in the eastern and northern parts of the study area, respectively. Heat flow computed from 1 – D modelling software and calibrated against BHT and reservoir temperatures suggests heat flow variations in the Niger Delta to range from 29 – 55 mW/m2 (0.69 – 1.31 HFU) with an average value of 42.5 mW/m2 (1.00 HFU). Lower heat flows(< 40 mW/m2) occur in the western and north central parts of the parts of the study area, and is likely to be influenced by high sedimentation rates. Higher heat flows (40 - 55 mW/m2) occur in the eastern and northwestern parts of the study area. Radiogenic heat production from crustal rocks and shale’s may account for the heat flow in the east. Hydrothermal convection is likely to have elevated the heat flow in the northwest. The hydrocarbon maturity modelling results show vast differences in timing and levels of kerogen transformation into petroleum. Result suggests that the potential source rocks (Paleocene, Eocene, Oligocene and partially the Lower Miocene) have attained maturity status to genereast and to the northwest.ate hydrocarbons. The depth to the onset of the oil window decreases from the west to the east and to the northwest.

Reservoir Characterisation and Simulation Study of the X Reservoir In the Ogbo Field of Theniger Delta

2017-06-11T23:54:20Z

Reservoir Characterisation and Simulation Study of the X Reservoir In the Ogbo Field of Theniger Delta Onwuka, Ogbonna Julius This study involves the understanding of the stratigraphic distribution of the area by integrating well logs, biostratigraphic data and seismic data to better define hydrocarbon reservoir distributions within the Middle to Late Miocene sediments in ‘’OGBO” Field Coastal swamp Depobelt of Niger Delta Basin. Sequence stratigraphic, geostatistical and structural analytical tool have been incorporated in this study, in order to achieve this. Based on the sequence stratigraphic studies, stratigraphic bounding surface such as Maximum Flooding Surfaces – MFS’s, Sequence Boundaries – SB’s and Transgressive Surface of Erosion – TSEs, were delineated and dated. The surfaces were correlated across various wells and mapped along dip and strikes lines on seismic sections, thus providing a good understanding of the stratigraphic distribution. In addition, genetic system tracts which include Lowstand System Tract – LST, Transgressive System Tract- TST and Highstand System Tract – HST, were recognized with the aid of sediment stacking patterns (progradational, retrogradational and aggradational stacks). This gave insight into reservoir, source, and seal rock distributions across the study area. Geostatistical analysis and petrophysical studies were carried out across reservoir tops of interest to determine variation in parameters such as porosity, permeability, water saturation, net to gross, etc. Structural analysis indicates the occurrence down to basin faults, deep seated rollovers, anticlinal structures, and dip fault closures at deeper intervals. These studies unraveled the existence of by-passed opportunities (B5000AB, C4000, D4100A and D4100AA prospects) which in no small measure led to an upward (about 3, 766, 750 MMBOE and 47, 376,962MMSCF) review of the hydrocarbon reserves in the field. This study led to the generation of a better and more reliable geological model for use in the reservoir studies of “OGBO” field.