Seismic interpretation and petrophysical evaluation of SH field, Niger Delta (original) (raw)
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Reservoir characterization is a process that involves the integration of various qualities and quantities of data in a consistent way to describe the reservoir properties of interest in each well locations. Characterizing the reservoir is a process which describes various properties in reservoirs using all the available data to provide reliable reservoir models for accurate prediction of the performance of a reservoir. Reservoir characterization is of high importance because it plays an important role in the exploration and exploitation processes of the oil and gas industry and also gives room for optimum recovery of hydrocarbon at a minimized cost. A play is one or more prospects that may define a profitable accumulation of undiscovered petroleum. Traditionally, a play is developed and evaluated without any particular petroleum system in mind. Wireline log data and 3D seismic data were analyzed to characterize the reservoir with respect to its porosity, water saturation, the volume of shale and permeability in “HARK” field. Reservoir “A” was delineated across four (4) wells-HARK_5, HARK_7, HARK_10 and HARK_11. The average permeabilities observed across the wells range from 1108.945mD to 1767.393mD, while the effective porosity ranges from 21.4% to 23.9%. The Hydrocarbon saturation ranges from 69.1% to 90.5% signifying the presence of a commercial quantity of hydrocarbon accumulation. Oil-Water Contact has been encountered by the well at 3814 m TVD. The volumetric analysis carried out revealed that the volume of hydrocarbon in place for reservoir “A” was estimated at 308 bb/STB. The outcome of this project is a notable approach in characterizing reservoirs and hydrocarbon producibility of the reservoir.
Journal of Petroleum Exploration and Production Technology
Seismic interpretation and petrophysical assessment of borehole logs from seven wells were integrated with the aim of establishing the hydrocarbon reserves prior to field development which will involve huge monetary obligation. Four hydrocarbonbearing sands, namely Pennay 1, 2, 3 and 4 were delineated from borehole log data. Four horizons corresponding to near top of mapped hydrocarbon-bearing sands were used to produce time maps and then depth structural maps using checkshot data. Three major structure-building faults (F2, F3 and F5 which are normal, listric concave in nature) and two antithetic (F1 and F4) were identified. Structural closures identified as rollover anticlines and displayed on the time/depth structure maps suggest probable hydrocarbon accumulation at the upthrown side of the fault F4. Petrophysical analysis of the mapped reservoirs showed that the reservoirs are of good quality and are characterized with hydrocarbon saturation ranging from 56 to 72%, volume of shale between 7 and 20% and porosity between 25 and 31%. Pennay 2 and 3 have a better relative petrophysical ranking compared to other mapped reservoirs in the study area. Dissimilarity in the petrophysical parameters and the uncertainty in the reservoir properties of the four reservoirs were considered in calculating range of values of gross rock volume (GRV) and oil in place volume. This research study revealed that the discovered hydrocarbon reserve resource accumulations in the Pennay field for the four-mapped reservoir sand bodies have a total proven (1P) reserve resource estimate of 53.005MMBO at P90, 59.013MMBO at 2P/P50 and 65.898MMBO at 3P/P10. Reservoir C, the only interval with a gas cap, has a volume of 7737MMscf of free gas at 1P, 8893.2MMscf at 2P and 10185.2MMscf at 3P. These oil and gas volumetric values yield at 1P/ P90 total of 137.30MMBOE, 154.9MMBOE at 2P and 171.515MMBOE at 3P. Reservoirs B and D have the highest recoverable oil at 1P, 2P, and 3P values of 5.265MMBO and 10.70MMBO, 12.053MMBO and 5.783MMBO, 13.557MMBO and 6.244MMBO, respectively.
Integration of Seismic and Petrophysics to Characterize Reservoirs in “ALA” Oil Field, Niger Delta
The Scientific World Journal, 2013
In the exploration and production business, by far the largest component of geophysical spending is driven by the need to characterize (potential) reservoirs. The simple reason is that better reservoir characterization means higher success rates and fewer wells for reservoir exploitation. In this research work, seismic and well log data were integrated in characterizing the reservoirs on "ALA" field in Niger Delta. Three-dimensional seismic data was used to identify the faults and map the horizons. Petrophysical parameters and time-depth structure maps were obtained. Seismic attributes was also employed in characterizing the reservoirs. Seven hydrocarbon-bearing reservoirs with thickness ranging from 9.9 to 71.6 m were delineated. Structural maps of horizons in six wells containing hydrocarbon-bearing zones with tops and bottoms at range of −2,453 to −3,950 m were generated; this portrayed the trapping mechanism to be mainly fault-assisted anticlinal closures. The identified prospective zones have good porosity, permeability, and hydrocarbon saturation. The environments of deposition were identified from log shapes which indicate a transitional-to-deltaic depositional environment. In this research work, new prospects have been recommended for drilling and further research work. Geochemical and biostratigraphic studies should be done to better characterize the reservoirs and reliably interpret the depositional environments.
In the exploration and production business, by far the largest component of geophysical spending is driven by the need to characterize (potential) reservoirs. The simple reason is that better reservoir characterization means higher success rates and fewer wells for reservoir exploitation. In this research work, seismic and well log data were integrated in characterizing the reservoirs on "ALA" field in Niger Delta. Three-dimensional seismic data was used to identify the faults and map the horizons. Petrophysical parameters and time-depth structure maps were obtained. Seismic attributes was also employed in characterizing the reservoirs. Seven hydrocarbon-bearing reservoirs with thickness ranging from 9.9 to 71.6 m were delineated. Structural maps of horizons in six wells containing hydrocarbon-bearing zones with tops and bottoms at range of −2,453 to −3,950 m were generated; this portrayed the trapping mechanism to be mainly fault-assisted anticlinal closures. The identified prospective zones have good porosity, permeability, and hydrocarbon saturation. The environments of deposition were identified from log shapes which indicate a transitional-to-deltaic depositional environment. In this research work, new prospects have been recommended for drilling and further research work. Geochemical and biostratigraphic studies should be done to better characterize the reservoirs and reliably interpret the depositional environments.
Petrophysical Analysis of Well Logs for the Estimation of Oil Reserves in Southern Niger Delta
International Journal of Advanced Geosciences, 2018
Gamma Ray log, Resistivity log, Density log, Micro-spherical focus log (MSFL), Deep Induction log (ILD) , Medium Induction log(ILM) and Spontaneous Potential (SP) log were collected for 2 wells in onshore Niger Delta. These insitu well logs were analyzed and interpreted. Porosity, permeability, water saturation, reservoir thickness and Shale volume were estimated for each hydrocarbon bearing zone delineated for each well. The parameters obtained were further analyzed and interpreted quantitatively to estimate the hydrocarbon potentials of each well. Twelve reservoir zones of interest (sand bodies) were delineated, correlated across the field and were ranked using average results of petrophysical parameters. In well one, Reservoirs E and F were identified as the thickest with 41ft each while reservoir A is the smallest in thickness (30ft). Petrophysical properties of hydrocarbon bearing zones delineated in well one ranged from 17.81% to 23.20% for porosity, 1292.09mD to 2018.17mD for permeability and 56.40% to 68.40% for hydrocarbon saturation compared to well 2 with 14.67% to 19.52% for porosity, 1211.61mD to1843.11mD for permeability and 51.80% to 66.40% for hydrocarbon saturation. The estimated averages of petrophysical properties for well one are 20.14% porosity, 1643.65mD permeability, 63.20% hydrocarbon saturation compared to well 2 with 15.55% porosity, 1582.58mD permeability and 61.93% hydrocarbon saturation. Results show 148.45MMBB and 145.91MMBB as oil reserve (Recoverable) for the field. From the results obtained, well one is likely to be more productive than well [2] and the field has exploitable oil in place.
Physical Science International Journal, 2015
Petrophysical analysis and volumetric estimation was carried out using 3D seismic and well log data to evaluate the reservoir potentials of Otu Field in the Niger Delta of Nigeria. Three hydrocarbon bearing reservoirs (C10, D10 and D31) were mapped out of several identified sands. The tops of these reservoirs were tied on the seismic section using checkshots and were traced throughout the seismic volume. Faults were mapped and structure maps for the three reservoir tops were produced. For C10 reservoir mapped at the depth of about 4512 feet, gas-down-to (GDT) was picked at 4525 feet and Oil-water contact (OWC) was picked at 4592 feet. For D10 reservoir mapped at the depth of about 5337 feet, oil-water contact was picked at 5404 feet and D31 reservoir which was mapped at depth 5536 feet has oil-water contact at 5675 feet. The gross thickness of the C10 reservoir sandstone formation ranges from 45 ft to 78.5 ft. Since the reservoir was intercalated with shale, the net thickness varied between 11.5ft and 54.5ft. The gross thickness of the D10 reservoir varied between 55.5 ft and 103 ft; while the net thickness varied between 13 ft and 51 ft. The gross thickness of D31 reservoir varied between 127.5 ft and 273 ft and the net thickness varied between 11 ft and 114 ft. The petrophysical parameters obtained were Obiekezie and Bassey; PSIJ, 6(1): 54-65, 2015; Article no.PSIJ.2015.033 55 porosity (ϕ) ranging from 0.32 to 0.34, water saturation (S w ) ranging from 0.23 to 0.29, hydrocarbon saturation (S H ) varies between 0.71 and 0.77 and net to gross (N/G) which ranges from 0.21 to 0.47. The volume of the closures (GRV) gotten from the structure maps were combined with the relevant petrophysical parameters to estimate the volume of hydrocarbon in place. The estimation of the volume of hydrocarbon revealed that C10 contains 45.98b ft 3 of gas and 95.18 million stock tank barrels of oil. The D10 and D31 reservoirs have oil with the volume estimated at 21.41 million stock tank barrels and 54.32 million stock tank barrels respectively. The study revealed that the field is prolific and the estimated volumes of hydrocarbon in the closures are satisfactory for further exploration work.
Advances in Petroleum Exploration and Development, 2018
In this study, well log derived petrophysical parameters of four (4) delineated clastic reservoirs in AK field, located onshore eastern Niger Delta have been effectively employed to characterize and assess hydrocarbon prospect potential of the field. Wireline well log data, 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 (S w) indicate that all reservoir units encountered in well AK-01 are oil saturated. However, only reservoir sands A1 and A2 are predominantly oil reservoirs in well AK02 while sands A3 and A4 plot in oil and water field. In well AK-03, reservoir A1 contains only oil while the remaining reservoirs contain oil and water. The reservoir units as encountered in well AK-04 show slightly different fluid saturation pattern as reservoir A1 contains only oil, A4 is gas saturated while the remaining two reservoir units (A3 and A4) plot in the field of both water and oil.
Hydrocarbon Reservoir Characterization of 'Khume' Field, Offshore Niger Delta, Nigeria
Journal of Geography, Environment and Earth Science International, 2021
The integrative approach of well log correlation and seismic interpretation was adopted in this study to adequately characterize and evaluate the hydrocarbon potentials of Khume field, offshore Niger Delta, Nigeria. 3-D seismic data and well logs data from ten (10) wells were utilized to delineate the geometry of the reservoirs in Khume field, and as well as to estimate the hydrocarbon reserves. Three hydrocarbon-bearing reservoirs of interest (D-04, D-06, and E-09A) were delineated using an array of gamma-ray logs, resistivity log, and neutron/density log suites. Stratigraphic interpretation of the lithologies in Khume field showed considerable uniform gross thickness across all three sand bodies. Results of petrophysical evaluations conducted on the three reservoirs correlated across the field showed that; shale volume ranged from 7-14%, total and effective porosity ranged from 1926% and 17-23% respectively, NTG from 42 to 100%, water saturation from 40%-100% and permeability from 1265-2102 mD. Seismic interpretation established the presence of both synthetic and antithetic faults. A total of six synthetic and four antithetic faults were interpreted from the study area. Horizons interpretation was done both in the strike and dip directions. Time and depth structure maps revealed reservoir closures to be anticlinal and fault supported in the field. Hydrocarbon volumes were calculated using the deterministic (map-based) approach. Stock tank oil initially in place (STOIIP) for the proven oil column estimated for the D-04 reservoir was 11.13 MMSTB, 0.54 MMSTB for D-06, and 2.16 MMSTB for E-09A reservoir. For the possible oil reserves, a STOIIP value of 7.28 MMSTB was estimated for D-06 and 6.30 MMSTB for E-09A reservoir, while a hydrocarbon initially in place (HIIP) of 4.13 MMSTB of oil equivalents was derived for the undefined fluid (oil/gas) in D-06 reservoir. A proven gas reserve of 1.07 MMSCF was derived for the D-06 reservoir. This study demonstrated the effectiveness of 3-D seismic and well logs data in delineating reservoir structural architecture and in estimating hydrocarbon volumes
Arabian Journal of Geosciences, 2016
Field evaluation in a complex sedimentary environment is always tedious due to problems associated with imaging of the subsurface in such areas. The 'Tadelu' field in Western Niger Delta, Nigeria, consists of a series of vertically stacked reservoirs in the Agbada Formation, thus making the field a complex sedimentary environment. The main objective of this study is to perform geophysical and petrophysical interpretations of properties that are typical of a shallow marine, transitional environment, with its attendant pattern of subsurface complexities, using 3D seismic and well log data. The approach adopted in achieving this objective included 3D seismic data interpretation, petrophysical rock typing, fluid typing and contact identification and determination of reservoir properties, onwards to reserve estimation for all the hydrocarbon-bearing reservoirs in the field. Five horizons as well as major and minor faults were mapped in the field, and five structural depth maps of reservoirs A, B, B1, C and C1 were generated within the objective depth interval to define the geometry of the reservoirs. Well log data from four wells in the field were studied to characterize the porosity, shale volume and water saturation of the reservoirs. The gamma ray (GR) logs were normalized and used in the computation of shale volume, while available density logs were used in the computation of porosities. Water saturation was determined using the Waxman-Smits model to take into consideration the shaly nature of the reservoir sands. The combination of porosity, shale volume and water saturation cutoff values was used in calculating net pay and net pay averages. The result of the structural interpretation shows that Tadelu field is characterized by two major faults and synthetic faults. The synthetic faults are dipping in northeast-southwest direction, and the closure formed by their hanging walls constitutes the target area for hydrocarbon in the field. However, within the reservoirs of Tadelu field, the net sand range is from 0.17 to 0.99 ft, having an average porosity in the range of 22 to 27 %. Water saturation average ranged from a minimum of 19 to a maximum of 27 %. Porosity in the field is high on the average due to very good to excellent sand quality. These petrophysical deliverables served as an input in the estimation of reserves. The gross rock volume (GRV) was determined by establishing a cutoff at appropriate contact(s). Reserve estimation was performed for the hydrocarbon-bearing sands and a total proven recoverable oil and gas estimate put at 42.797 MMbbl and 13.256 Bscf, respectively. Keywords 'Tadelu' Field. Niger Delta. Gross rock volume. Vertically stacked reservoirs. Shallow marine
Journal of Petroleum Exploration and Production Technology
Adequate analyses of seismic and petrophysical data help to minimize drilling risk and maximize well and reservoir productivity. Reservoir characterization was carried out to provide information and improve understanding of the geological and petrophysical parameters, and hence improve decision making regarding the development of the field under study. Wireline logs obtained from three wells as well as a 3D Seismic data coverage of G-field in the Niger Delta were evaluated using the petrel software. Suites of gamma and deep resistivity logs aided the delineation and correlation of the sandstone unit, while the top was tied to the seismic data using synthetic seismogram to determine seismic characters. Well correlation enabled the delineation of reservoir sand across the wells. The quality of the reservoir was determined from petrophysical averages, in which the reservoir has an average thickness of 72 m, average porosity of 0.31, average net to gross of 0.75, average V-shale of 0.25, and average water saturation of 0.19, respectively. Listric normal faults were mapped across the field. The models reveal lateral and horizontal variations in reservoir properties which capture subsurface heterogeneity and anisotropy across the reservoir sand, and also possible sweet-spot zones were identified. These are diagnostic of areas for future exploitation and recovery of hydrocarbon. Seismic attributes analysis was done to predict variation in lithofacies across the sandstone body.