scholarly journals Stochastic modelling of spatial variability of petrophysical properties in parts of the Niger Delta Basin, southern Nigeria

2019 ◽  
Vol 10 (2) ◽  
pp. 569-585 ◽  
Author(s):  
Ebong D. Ebong ◽  
Anthony E. Akpan ◽  
Stephen E. Ekwok
Keyword(s):  
Spatial Variability ◽  
Niger Delta ◽  
Water Saturation ◽  
Stochastic Modelling ◽  
Sequential Gaussian Simulation ◽  
Stochastic Methods ◽  
Petrophysical Properties ◽  
Reservoir Properties ◽  
Petrophysical Property ◽  
Niger Delta Basin

Abstract Three-dimensional models of petrophysical properties were constructed using stochastic methods to reduce ambiguities associated with estimates for which data is limited to well locations alone. The aim of this study is to define accurate and efficient petrophysical property models that best characterize reservoirs in the Niger Delta Basin at well locations and predicting their spatial continuities elsewhere within the field. Seismic data and well log data were employed in this study. Petrophysical properties estimated for both reservoirs range between 0.15 and 0.35 for porosity, 0.27 and 0.30 for water saturation, and 0.10 and 0.25 for shale volume. Variogram modelling and calculations were performed to guide the distribution of petrophysical properties outside wells, hence, extending their spatial variability in all directions. Transformation of pillar grids of reservoir properties using sequential Gaussian simulation with collocated cokriging algorithm yielded equiprobable petrophysical models. Uncertainties in petrophysical property predictions were performed and visualized based on three realizations generated for each property. The results obtained show reliable approximations of the geological continuity of petrophysical property estimates over the entire geospace.

scholarly journals Stochastic reservoir modelling for prospect mapping: a case study of ''bright'' field, Niger delta

2020 ◽  
Vol 8 (1) ◽  
pp. 102
Author(s):  
James Sunday Abe ◽  
Mary Taiwo Olowokere ◽  
Pius Adekunle Enikanselu
Keyword(s):  
Water Saturation ◽  
Stochastic Modelling ◽  
Total Porosity ◽  
Effective Porosity ◽  
Sequential Gaussian Simulation ◽  
Reservoir Modeling ◽  
Reservoir Modelling ◽  
Petrophysical Property ◽  
Geostatistical Approach ◽  
Net To Gross

Deterministic reservoir modeling using geostatistical approach is inherently ambiguous because of the uncertainties contained in the generated reservoir models. Stochastic reservoir modelling using sequential gaussian simulation algorithm can resolve this problem by generating various realizations of petrophysical property models in order to map this uncertainties caused by subsurface heterogeneity. Suites of well logs for four wells with seismic data in SEG-Y format were used for this analysis. The wells were correlated and a reservoir was mapped across them in other to map their lateral extent, synthetic seismogram was generated in other to match the event on the seismic with that of the synthetic after carrying out a shift of -12ms. Seismic to well tie was done to ensure that the horizons were mapped accurately. The structural maps generated and the wells were input that goes into the stochastic modelling process. Five realizations each of facies(lithology), effective porosity, total porosity, net to gross, volume of shale and one realization for permeability and water saturation were generated. The facies models showed the distribution of sand and shale with sand at the existing well locations and the effective porosity, total porosity, net to gross, volume of shale models showed excellent values around the well location. Permeability and water saturation models showed that the existing wells were drilled at the flank of the anticlinal structure. Two drillable points (prospects) were proposed by considering all the initial petrophysical property models and the parameters of the two points named P1 and P2 showed that they contain hydrocarbon in commercial quantity. Stochastic reservoir modelling has proved effective in mapping uncertainties and detecting bypassed hydrocarbons.  

scholarly journals A Practical Method to Calculate and Model the Petrophysical Properties of Reservoir Rock Using Petrel Software: A case Study from Iraq

2020 ◽  
pp. 2640-2650
Author(s):  
Sarah Taboor Wali ◽  
Hussain Ali Baqer
Keyword(s):  
Water Saturation ◽  
Three Dimensional ◽  
Carbonate Reservoir ◽  
Reservoir Rock ◽  
Sequential Gaussian Simulation ◽  
Geological Model ◽  
Petrophysical Properties ◽  
Reservoir Properties ◽  
Software Models ◽  
Average Water

Nasiriyah oilfield is located in the southern part of Iraq. It represents one of the promising oilfields. Mishrif Formation is considered as the main oil-bearing carbonate reservoir in Nasiriyah oilfield, containing heavy oil (API 25o(. The study aimed to calculate and model the petrophysical properties and build a three dimensional geological model for Mishrif Formation, thus estimating the oil reserve accurately and detecting the optimum locations for hydrocarbon production. Fourteen vertical oil wells were adopted for constructing the structural and petrophysical models. The available well logs data, including density, neutron, sonic, gamma ray, self-potential, caliper and resistivity logs were used to calculate the petrophysical properties. The interpretations and environmental corrections of these logs were performed by applying Techlog 2015 software. According to the petrophysical properties analysis, Mishrif Formation was divided into five units (Mishrif Top, MA, shale bed, MB1 and MB2).    A three-dimensional geological model, which represents an entrance for the simulation process to predict reservoir behavior under different hydrocarbon recovery scenarios, was carried out by employing Petrel 2016 software. Models for reservoir characteristics (porosity, permeability, net to gross NTG and water saturation) were created using the algorithm of Sequential Gaussian Simulation (SGS), while the variogram analysis was utilized as an aid to distribute petrophysical properties among the wells.      The process showed that the main reservoir unit of Mishrif Formation is MB1 with a high average porosity of 20.88% and a low average water saturation of 16.9%. MB2 unit has good reservoir properties characterized by a high average water saturation of 96.25%, while MA was interpreted as a water-bearing unit. The impermeable shale bed unit is intercalated between MA and MB1 units with a thickness of 5-18 m, whereas Mishrif top was interpreted as a cap unit. The study outcomes demonstrated that the distribution accuracy of the petrophysical properties has a significant impact on the constructed geological model which provided a better understanding of the study area’s geological construction. Thus, the estimated reserve h was calculated to be about 7945 MSTB. This can support future reservoir development plans and performance predictions. 

scholarly journals Hydrocarbon Prospectivity in the undrilled area of AIMA Field in the Niger Delta Basin, Nigeria.

2021 ◽  
Vol 6 (1) ◽  
pp. 34-41
Author(s):  
Alexander Ogbamikhumi ◽  
John Elvis Ighodalo
Keyword(s):  
Neural Network ◽  
Artificial Neural Network ◽  
Niger Delta ◽  
Water Saturation ◽  
Poisson Ratio ◽  
Rock Physics ◽  
Reservoir Properties ◽  
Field Development ◽  
Seismic Reservoir ◽  
Niger Delta Basin

Field development is a very costly endeavor that requires drilling several wells in an attempt to understanding potential prospects. To help reduce the associated cost, this study integrates well and seismic based rock physics analysis with artificial neural network to evaluation identified prospects in the field.  Results of structural and amplitude maps of three major reservoir levels revealed structural highs typical of roll over anticlines with amplitude expression that conforms to structure at the exploited zone where production is currently ongoing. Across the bounding fault to the prospective zones, only the D_2 reservoir possessed the desired amplitude expression, typical of hydrocarbon presence. To validate the observed amplitude expression at the prospective zone, well and seismic based rock physics analyses were performed. Results from the analysis presented Poisson ratio, Lambda-Rho and Lambda/Mu-Rho ratio as good fluid indicator while Mu-Rho was the preferred lithology indicator.  These rock physics attributes were employed to validate the observed prospective direct hydrocarbon indicator  expressions on seismic. Reservoir properties maps generated for porosity and water saturation prediction using Probability Neural Network gave values of 20-30% and 25-35% for water saturation and porosity respectively, indicating  the presence of good quality hydrocarbon bearing reservoir at the prospective zone.

scholarly journals Characterization and geostatistical modeling of reservoirs in ‘Falad’ field, Niger Delta, Nigeria

2021 ◽  
Author(s):  
Ayodele O. Falade ◽  
John O. Amigun ◽  
Yousif M. Makeen ◽  
Olatunbosun O. Kafisanwo
Keyword(s):  
Niger Delta ◽  
Structural Model ◽  
Water Saturation ◽  
Sequential Gaussian Simulation ◽  
Surface Generation ◽  
Geostatistical Modeling ◽  
Reservoir Properties ◽  
Field Development ◽  
Net To Gross ◽  
Well Data

AbstractThis research aims at characterizing and modeling delineated reservoirs in ‘Falad’ Field, Niger Delta, Nigeria, to mitigate the challenge caused by the heterogeneous nature of the reservoirs. Seismic and well log data were integrated, and geostatistics was applied to describe the reservoir properties of the interwell spaces within the study area. Four reservoirs, namely RES 1, RES 2, RES 3 and RES 4, were delineated and correlated across four wells. The reservoir properties {lithology, net to gross, porosity, permeability, water saturation} of all the delineated reservoirs mapped were determined, and two reservoirs with the best quality were picked for further analysis (surface generation and modeling) after ranking the reservoirs based on their quality. Structural interpretation of the field was carried, nine faults were mapped (F1—F9), and the fault polygon was generated. The structural model showed the area is structurally controlled with two of the major faults mapped (F1 and F3) oriented in the SW–NE direction while the other one (F4) is oriented in the NW–SE direction. A 3D grid was constructed using the surfaces of the delineated reservoirs and the reservoir properties were distributed stochastically using simple krigging method with sequential Gaussian simulation, sequential indicator simulation and Gaussian random function simulation algorithms. Geostatistical modeling used in this study has been able to give subsurface information in the areas deficient of well data as the estimated reservoir properties gotten from existing wells have been spatially distributed in the study area and will thus aid future field development while also they are used in identifying new prospect by combining property models with structural maps of the area.

Evaluation of Reservoir’s Petrophysical Parameters, Niger Delta, Nigeria

2017 ◽  
Vol 5 (1) ◽  
pp. 19
Author(s):  
Ubong Essien ◽  
Akaninyene Akankpo ◽  
Okechukwu Agbasi
Keyword(s):  
Niger Delta ◽  
Gamma Ray ◽  
Water Saturation ◽  
Petrophysical Parameters ◽  
Niger Delta Region ◽  
Average Porosity ◽  
Irreducible Water Saturation ◽  
Open Hole ◽  
Bulk Volume ◽  
Niger Delta Basin

Petrophysical analysis was performed in two wells in the Niger Delta Region, Nigeria. This study is aimed at making available petrophysical data, basically water saturation calculation using cementation values of 2.0 for the reservoir formations of two wells in the Niger delta basin. A suite of geophysical open hole logs namely Gamma ray; Resistivity, Sonic, Caliper and Density were used to determine petrophysical parameters. The parameters determined are; volume of shale, porosity, water saturation, irreducible water saturation and bulk volume of water. The thickness of the reservoir varies between 127ft and 1620ft. Average porosity values vary between 0.061 and 0.600; generally decreasing with depth. The mean average computed values for the Petrophysical parameters for the reservoirs are: Bulk Volume of Water, 0.070 to 0.175; Apparent Water Resistivity, 0.239 to 7.969; Water Saturation, 0.229 to 0.749; Irreducible Water Saturation, 0.229 to 0.882 and Volume of Shale, 0.045 to 0.355. The findings will also enhance the proper characterization of the reservoir sands.

scholarly journals An Integrated Microfacies and Well Logs-Based Reservoir Characterization of Yamama Formation, Southern Iraq

2021 ◽  
pp. 3570-3586
Author(s):  
Mohanad M. Al-Ghuribawi ◽  
Rasha F. Faisal
Keyword(s):  
Reservoir Characterization ◽  
Water Saturation ◽  
Effective Porosity ◽  
Well Logs ◽  
Petrophysical Properties ◽  
Reservoir Properties ◽  
Thin Sections ◽  
Porosity And Permeability ◽  
South Of Iraq ◽  
Southern Iraq

     The Yamama Formation includes important carbonates reservoir that belongs to the Lower Cretaceous sequence in Southern Iraq. This study covers two oil fields (Sindbad and Siba) that are distributed Southeastern Basrah Governorate, South of Iraq. Yamama reservoir units were determined based on the study of cores, well logs, and petrographic examination of thin sections that required a detailed integration of geological data and petrophysical properties. These parameters were integrated in order to divide the Yamama Formation into six reservoir units (YA0, YA1, YA2, YB1, YB2 and YC), located between five cap rock units. The best facies association and petrophysical properties were found in the shoal environment, where the most common porosity types were the primary (interparticle) and secondary (moldic and vugs) . The main diagenetic process that occurred in YA0, YA2, and YB1 is cementation, which led to the filling of pore spaces by cement and subsequently decreased the reservoir quality (porosity and permeability). Based on the results of the final digital  computer interpretation and processing (CPI) performed by using the Techlog software, the units YA1 and YB2 have the best reservoir properties. The unit YB2 is characterized by a good effective porosity average, low water saturation, good permeability, and large thickness that distinguish it from other reservoir units.

scholarly journals Petrophysical evaluation of reservoir sand bodies in Kwe Field Onshore Eastern Niger Delta

2016 ◽  
Vol 20 (2) ◽  
pp. 383-393
Author(s):  
T.M. Asubiojo ◽  
S.E. Okunuwadje
Keyword(s):  
Niger Delta ◽  
Depositional Environment ◽  
Gamma Ray ◽  
Petrophysical Properties ◽  
System Quality ◽  
Flow Units ◽  
Wireline Logs ◽  
And Performance ◽  
Niger Delta Basin ◽  
Sand Bodies

Reservoir sand bodies in Kwe Field, coastal swamp depobelt, onshore eastern Niger Delta Basin were evaluated from a composite log suite comprising gamma ray, resistivity, density and neutron logs of five (5) wells with core photographs of one (1) reservoir of one well. The aim of the study was to evaluate the petrophysical properties of the reservoirs while the objectives were to identify the depositional environment and predict the reservoir system quality and performance. The study identified three reservoir sand bodies in the field on the basis of their petrophysical properties and architecture. Reservoir A has an average NTG (61.4 %), Ø (27.50 %), K (203.99 md), Sw (31.9 %) and Sh (68.1 %); Reservoir B has an average NTG (65.6 %), Ø (26.0 %), K (95.90 md), Sw (28.87 %) and Sh (71.13 %) while Reservoir C has an average NTG (70.4 %), Ø (26.1 %), K (91.4 md), Sw (25.0 %) and Sh (75.03 %) and therefore show that the field has good quality sandstone reservoirs saturated in hydrocarbon. However, the presence of marine shales (or mudstones) interbedding with these sandstones may likely form permeability baffles to vertical flow and compartmentalize the reservoirs. These reservoirs may therefore have different flow units. Integrating wireline logs and core data, the reservoir sand bodies were interpreted as deposited in an estuarineshoreface setting thus indicating that the Kwe Field lies within the marginal marine mega depositional environment.Keywords: Estuarine, Shoreface, Reservoir, Sand, Kwe, field

scholarly journals Shale volume and permeability of the Miocene unconsolidated turbidite sands of Bonga oil field, Niger delta, Nigeria

2017 ◽  
Vol 5 (1) ◽  
pp. 37 ◽  
Author(s):  
Inyang Namdie ◽  
Idara Akpabio ◽  
Agbasi Okechukwu .E.
Keyword(s):  
Niger Delta ◽  
Gamma Ray ◽  
Water Saturation ◽  
Strong Dependence ◽  
Water Injection ◽  
Oil Field ◽  
Reservoir Properties ◽  
Injection Wells ◽  
Log Data ◽  
Shale Volume

Bonga oil field is located 120km (75mi) southeast of the Niger Delta, Nigeria. It is a subsea type development located about 3500ft water depth and has produced over 330 mmstb of hydrocarbon till date with over 16 oil producing and water injection wells. The producing formation is the Middle to Late Miocene unconsolidated turbidite sandstones with lateral and vertical homogeneities in reservoir properties. This work, analysis the petrophysical properties of the reservoir units for the purpose of modeling the effect of shale content on permeability in the reservoir. Turbidite sandstones are identified by gamma-ray log signatures as intervals with 26-50 API, while sonic, neutron, resistivity, caliper and other log data are applied to estimate volume of shale ranging between 0.972 v/v for shale intervals and 0.0549 v/v for turbidite sands, water saturation of 0.34 v/v average in most sand intervals, porosity range from 0.010 for shale intervals to 0.49 v/v for clean sands and permeability values for the send interval 11.46 to2634mD, for intervals between 7100 to 9100 ft., Data were analyzed using the Interactive Petrophysical software that splits the whole curve into sand and shale zones and estimates among other petrophysical parameters the shale contents of the prospective zones. While Seismic data revealed reservoir thickness ranging from 25ft to over 140ft well log data within the five wells have identified sands of similar thickness and estimated average permeability of700mD. Within the sand units across the five wells, cross plots of estimated porosity, volume of shale and permeability values reveal strong dependence of permeability on shale volume and a general decrease in permeability in intervals with shale volume. It is concluded that sand units with high shale contents that are from0.500 to0.900v/v will not provide good quality reservoir in the field.

Integrated workflow approach to static modeling of Igloo R3 reservoir, onshore Niger Delta, Nigeria

2015 ◽  
Vol 3 (3) ◽  
pp. SZ1-SZ14 ◽  
Author(s):  
Emmanuel Kenechukwu Anakwuba ◽  
Clement Udenna Onyekwelu ◽  
Augustine Ifeanyi Chinwuko
Keyword(s):  
Correlation Coefficient ◽  
Acoustic Impedance ◽  
Niger Delta ◽  
Seismic Inversion ◽  
Distribution Functions ◽  
Cumulative Distribution ◽  
Sequential Gaussian Simulation ◽  
Reservoir Properties ◽  
Static Modeling ◽  
Geophysical Well Logs

We constructed a 3D static model of the R3 reservoir at the Igloo Field, Onshore Niger Delta, by integrating the 3D seismic volume, geophysical well logs, and core petrophysical data. In this model, we used a combined petrophysical-based reservoir zonation and geostatistical inversion of seismic attributes to reduce vertical upscaling problems and improve the estimation of reservoir properties between wells. The reservoir structural framework was interpreted to consist of three major synthetic faults; two of them formed northern and southern boundaries of the field, whereas the other one separated the field into two hydrocarbon compartments. These compartments were pillar gridded into 39,396 cells using a [Formula: see text] dimension over an area of [Formula: see text]. Analysis of the field petrophysical distribution showed an average of 21% porosity, 34% volume of shale, and 680-mD permeability. Eleven flow units delineated from a stratigraphic modified Lorenz plot were used to define the reservoir’s stratigraphic framework. The calibration of acoustic impedance using sonic- and density-log porosity showed a 0.88 correlation coefficient; this formed the basis for the geostatistic seismic inversion process. The acoustic impedance was transformed into reservoir parameters using a sequential Gaussian simulation algorithm with collocated cokriging and variogram models. Ten equiprobable acoustic impedance models were generated and further converted into porosity models by using their bivariate relationship. We modeled the permeability with a single transform of core porosity with a correlation coefficient of 0.86. We compared an alternative model of porosity without seismic as a secondary control, and the result showed differences in their spatial distributions, which was a major control to fluid flow. However, there were similarities in their probability distribution functions and cumulative distribution functions.

scholarly journals Hydrocarbon reservoir characterization of “Otan-Ile” field, Niger Delta

2021 ◽  
Vol 11 (2) ◽  
pp. 601-615
Author(s):  
Tokunbo Sanmi Fagbemigun ◽  
Michael Ayu Ayuk ◽  
Olufemi Enitan Oyanameh ◽  
Opeyemi Joshua Akinrinade ◽  
Joel Olayide Amosun ◽  
...  
Keyword(s):  
Niger Delta ◽  
Reservoir Characterization ◽  
Water Saturation ◽  
Structural Deformation ◽  
Well Log ◽  
Reservoir Properties ◽  
Good Tool ◽  
Log Data ◽  
Hydrocarbon Reservoir ◽  
Hydrocarbon Saturation

AbstractOtan-Ile field, located in the transition zone Niger Delta, is characterized by complex structural deformation and faulting which lead to high uncertainties of reservoir properties. These high uncertainties greatly affect the exploration and development of the Otan-Ile field, and thus require proper characterization. Reservoir characterization requires integration of different data such as seismic and well log data, which are used to develop proper reservoir model. Therefore, the objective of this study is to characterize the reservoir sand bodies across the Otan-Ile field and to evaluate the petrophysical parameters using 3-dimension seismic and well log data from four wells. Reservoir sands were delineated using combination of resistivity and gamma ray logs. The estimation of reservoir properties, such as gross thickness, net thickness, volume of shale, porosity, water saturation and hydrocarbon saturation, were done using standard equations. Two horizons (T and U) as well as major and minor faults were mapped across the ‘Otan-Ile’ field. The results show that the average net thickness, volume of shale, porosity, hydrocarbon saturation and permeability across the field are 28.19 m, 15%, 37%, 71% and 26,740.24 md respectively. Two major faults (F1 and F5) dipping in northeastern and northwestern direction were identified. The horizons were characterized by structural closures which can accommodate hydrocarbon were identified. Amplitude maps superimposed on depth-structure map also validate the hydrocarbon potential of the closures on it. This study shows that the integration of 3D seismic and well log data with seismic attribute is a good tool for proper hydrocarbon reservoir characterization.

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