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Abstract Several criteria and strategies have been developed to predict sand failures and to select appropriate sand control methods for improved completion designs and to maximise oil production at moderate unit technical cost. The depth criterion, SPADE equation, Rock Mechanic Equations incorporating Brinell Hardness Number and Unconfined Compressive Strength have been used extensively to predict sand production tendencies and to propose completion types. None of these criteria and strategies has explicitly incorporated the depositional environmental factor that defines the origin of these oil-bearing formations. A recent study aimed to correlate depo-belts and depositional environments to actual sand production using historical data of producing wells in the Niger Delta but covered only the Greater Ughelli depo-belt to some depths (SPE-163010). That study indicated a predominance of high sand producers in the channel sands depositional environment of the Greater Ughelli Depobelt. This paper therefore seeks to complete the investigation across all the remaining depo-belts and litho-facies and to share the review outcomes/findings with the goal of establishing correlation between known rock mechanic principles and models used in sand failure prediction and sand control selection as a total system approach, providing wider solutions to sand control challenges in the oil industry.
- Geology > Sedimentary Geology > Depositional Environment (1.00)
- Geology > Geological Subdiscipline > Geomechanics (1.00)
- Geology > Rock Type > Sedimentary Rock > Clastic Rock (0.49)
- Energy > Oil & Gas > Upstream (1.00)
- Government > Regional Government > North America Government > United States Government (0.46)
- Europe > Netherlands > Groningen > Southern North Sea - Anglo Dutch Basin > Groningen License > Groningen Field > Upper Rotliegend Formation (0.99)
- Europe > Netherlands > Groningen > Southern North Sea - Anglo Dutch Basin > Groningen License > Groningen Field > Limburg Formation (0.99)
- Asia > Brunei > Belait District > Rasau Field (0.99)
- Africa > Nigeria > Niger Delta > Niger Delta Basin (0.99)
- Reservoir Description and Dynamics > Reservoir Characterization > Exploration, development, structural geology (1.00)
- Reservoir Description and Dynamics > Formation Evaluation & Management > Open hole/cased hole log analysis (1.00)
- Reservoir Description and Dynamics > Reservoir Characterization > Sedimentology (0.94)
- (4 more...)
Abstract Prospectivity review of the northern part of OML 20 located in the oldest depobelt of the Niger Delta (Northern Delta depobelt) was carried out following the acquisition of 3D seismic data in this predominantly 2D covered area. The only giant field in the Northern Delta Depobelt is the Oguta field and was drilled based on 2D seismic data in 1965. Acquisition of 3D seismic data and its interpretation has changed the structural understanding in this part of the delta and has resulted in the identification of the Oguta North prospect, which is a large fault bounded hanging wall closure against a northwest to southeast trending fault block north of the Akri-Oguta field. The culmination of this prospect is against an oblique fault that could not be defined on the previously sub-optimally acquired old 2D. The prospect is a material opportunity of about 15 km2, with a vertical closure of about 2000 ft. The objective interval ranges in age from Late Eocene to Early Oligocene when the delta was essentially lobate and presumably river dominated. At Oguta-Akri field to the south the objective interval is about 2000โ3000ft with deposition in deltaic shoreface to shelf environments. These sediments vary northwards to more proximal environments at the Oguta North prospect. Reservoir thicknesses from the correlating intervals range from 30 -250 ft. The main risks associated with this prospect include lack of amplitude support in the main reservoirs, possible fault seal failure and the lateral extent of some of the reservoirs. Introduction The Oguta North cluster of consists of three prospects. Together these prospects form a material opportunity. The Oguta North prospect is a large fault bounded closure, within a NW-SE trending fault block, north of the Akri-Oguta field (Fig. 1). The prospect is located in SPDC East's OML 20; it straddles ADDAX's OPL118 and has an areal closure ranging from about 14 sq. km at the shallowest objective level (D1.0) to about 15 sq. km at depth.
- Africa > Niger (1.00)
- Africa > Nigeria > Gulf of Guinea > Niger Delta > Imo State (0.79)
- Africa > Nigeria > Gulf of Guinea > Niger Delta > Rivers State (0.49)
- Phanerozoic > Cenozoic > Paleogene > Eocene > Priabonian (0.34)
- Phanerozoic > Cenozoic > Paleogene > Eocene > Bartonian (0.34)
- Geology > Structural Geology > Fault (1.00)
- Geology > Geological Subdiscipline > Stratigraphy (1.00)
- Geology > Sedimentary Geology (0.90)
- Africa > Nigeria > Gulf of Guinea > Rivers > Niger Delta > Niger Delta Basin > OML 60 > Odugri Field (0.99)
- Africa > Nigeria > Gulf of Guinea > Rivers > Niger Delta > Niger Delta Basin > OML 60 > Akri Field (0.99)
- Africa > Nigeria > Gulf of Guinea > Imo > Niger Delta > Niger Delta Basin > OML 60 > Oguta Field (0.99)
- (6 more...)
Petrophysical Evaluation and Sequence Stratigraphic Model of โIndigo Field' in Greater Ughelli Depobelt, Niger Delta, Nigeria
Okeke, Chinwendu O. (University of Nigeria) | Mode, Ayonma W. (University of Nigeria) | Obi, Ifeanyichukwu S. (University of Nigeria) | Odokoh, Anthony O. (Nigerian Agip Oil Company)
Abstract Detailed Petrophysical studies and Sequence stratigraphic analyses of three wells in the 'Indigo Field of Niger Delta was carried out using wireline logs and high resolution biostratigraphy. Three sequence boundaries (SB 27.3Ma, 29.3Ma and 32.4Ma) and maximum flooding surfaces (MFS 26.2Ma, 28.1Ma and 31.3Ma) were identified. Three systems tracts were delineated in wells A and B, while only two were delineated in well C. Nine reservoir units (A1-A9) analyzed in well A show porosity, permeability and Vshale of 13โ18%, 89.35โ2775.8md and 0.026โ0.05v/v decimal, respectively. Reservoirs A1, A4, A7, A8, and A9 contain oil, A2 and A3 contain gas, and A5 and A6 contain water. Porosity and Vshale values for three reservoir units in well B (B1-B3) are 16โ25% and 0.03โ0.045v/v decimal, respectively. Reservoirs B1 and B2 contain water, and B3 contains gas. Six reservoir units (C1-C6) delineated in well C have average porosity, permeability and Vshale values of 19โ24%, 1063.92โ3674.4md and 0.05โ0.1v/v decimal, respectively. Reservoir C1 contains oil and water; C2, C3 and C6 contain only water, and C4 and C5 contain oil only. Water saturation, moveable hydrocarbon index (MHI) and net sand count were 14โ79%, 0.42โ0.46, and 6โ40m respectively, in well A; 24โ65%, 0.55โ0.56 and 7โ26m in well B; and 21โ67%, 0.44โ0.54 and 11โ22m in well C. Well A, being with thicker and more porous sands with lower Vshale is more productive than wells B and C. Introduction The Niger Delta depocentres have been extensively studied to explore for subtle, structural and stratigraphic traps 1. In order to meet oil demands over the years, different geophysical and geochemical methods have been employed to exploit for oil. Procedures related to the exploration of oil are very complex, expensive and require large volume of data and it is necessary to consider the risk associated with geological, economical and technological uncertainties. In this study carried out on the โIndigo Fieldโ Niger Delta Basin predictions of the reservoir units, seal, possible source rocks and fluid type in the reservoirs using petrophysical and sequence stratigraphic tools were employed to give the nature and quality of clastic reservoirs and to predict their development and distribution in this field.
- Africa > Nigeria > Niger Delta (1.00)
- Africa > Niger (1.00)
- Geology > Geological Subdiscipline > Stratigraphy > Sequence Stratigraphy (1.00)
- Geology > Rock Type > Sedimentary Rock > Clastic Rock > Mudrock > Shale (0.36)
- Africa > Nigeria > Niger Delta > Niger Delta Basin (0.99)
- Africa > Nigeria > Anambra Basin (0.99)
- Africa > Cameroon > Akata Formation (0.99)
- Reservoir Description and Dynamics > Reservoir Characterization > Geologic modeling (1.00)
- Reservoir Description and Dynamics > Reservoir Characterization > Exploration, development, structural geology (1.00)
- Reservoir Description and Dynamics > Formation Evaluation & Management > Open hole/cased hole log analysis (1.00)
Estimation of Reservoir Permeability Using Analogue Core Data for Green Field: Case Studies from Niger Delta
Das, Anindya (Shell Petroleum Development Company of Nigeria Limited) | Anijekwu, Chinedu (Shell Petroleum Development Company of Nigeria Limited) | Maguire, Kelly (Shell Petroleum Development Company of Nigeria Limited) | Wood, Mark (Shell Petroleum Development Company of Nigeria Limited) | Akinrolabu, Segun (Shell Petroleum Development Company of Nigeria Limited) | Adenaiye, Olaniyi (Shell Petroleum Development Company of Nigeria Limited) | Iyowu, Olakunle (Shell Petroleum Development Company of Nigeria Limited) | Duvbiama, Omolara (Shell Petroleum Development Company of Nigeria Limited) | Ozoemene, Uche (Shell Petroleum Development Company of Nigeria Limited) | Amrasa, Kefe (Shell Petroleum Development Company of Nigeria Limited)
Abstract Permeability is one of the most important parameters of reservoir rocks; it defines the capacity of rocks to transmit fluids in pore spaces. Permeability prediction is of extreme importance in deciding the field development strategy for green reservoirs. The reservoir rocks are made up of grains, cement and pore network. The pore network is made up of larger spaces, referred to as pores, which are connected by small spaces referred to as throats. The pore spaces control the amount of porosity, while the pore throats control the movement of fluids and the quantity of rock permeability. Generally, the sources of permeability measurements in green field are from core data, well test data and Nuclear Magnetic Resonance (NMR) data. However, core information, well test information and NMR information are usually very limited due to high cost of acquisition making justification usually difficult. The consequence is that we have very low ratio of cored to the total reservoirs in the Niger Delta. This paper discusses a methodology for accurately estimating permeability using analogue fields/reservoirs core data in green reservoirs. The main factors to consider in choosing a suitable analogue includes Facies classification, relative depth of the reservoirs, average porosity and histogram of the Gamma ray values between the subject and analogue reservoirs. This selection is usually an integrated effort between the teams Geologist and Petrophysicist. In this study, two fields were selected where permeability prediction was based on analogue core data. A robust Niger delta wide analogue selection process was applied first to identify the analogue field where core data exists. After selection of the analogue field, facies-wise poroperm transform was built. This poroperm transforms were then validated in one of the fields where real core measurements were available post study. This blind test with real core permeability data indicated an excellent match with analogue based permeability model. In the other field, the analogue based permeability was validated against NMR and mobility data acquired in some of the reservoirs. This workflow establishes the robustness of using existing analogue data to reduce the subsurface uncertainty and justify an integrated workflow of estimating permeability in the green field rather than acquiring a new data to support development decision.
Abstract The Lower Miocene strata of the gas-rich X, Y and Z oil fields in the Central Swamp depobelt of the Niger Delta, is evaluated in terms of its sequence stratigraphic architecture. The penetrated interval includes three superimposed estuarine valley-fill sequences (S1: 17.7Ma-16.7Ma; S2: 16.7Ma-15.5Ma; S3: 15.5Ma-13.1Ma). Apart from Field Z where S3 includes a lowstand systems tract, each valley-fill contains a fluvio-estuarine transgressive systems tract (TST) and a highstand systems tract (HST). This stratigraphic architecture appears to have a strong influence on reservoir properties and petroleum resource distribution. The bulk of the total original oil in place in Field X and Field Y, which occurs in narrow, wedge-shaped, discrete/amalgamated, proximal fluviatile-distal marine sand bodies encased in marine shales, are restricted to the 17.7Ma-17.4Ma transgressive estuarine valley fill of S1. In Field Z, the productive reservoir consists of alternation of detached shoreface sand lobes and outer neritic-bathyal shale. This reservoir occurs within the 15.5Ma-15.0Ma lowstand and transgressive systems tract of S3. Highest quality and greatest degree of homogeneity are indicated for Field X and Field Y reservoirs. Sand body geometry and heterogeneity in internal architecture of Field Z reservoir account for the more complex lateral and vertical fluid flow reported from this field. The new knowledge of the depositional characteristics of the reservoirs and the genetic relationship among the oilfields minimises geological and dynamic uncertainties in the inter-field development plan. Introduction The sequence stratigrphic concept provides an excellent tool that addresses the problems of genetic relationships among oilfields and reservoirs, as well as sand development and property distribution. This report which focuses on the Central Swamp depobelt of the Niger Delta, evaluates the sequence stratigraphic architecture of X, Y and Z oilfields (Fig. 1). The three fields were discovered in 1971, 1966 and 1961 respectively. Field Y is separated from Field X to the north, by a major fault and from Field Z to the south by a macrostructure-bounding fault. Each of the three fields contains one major oil reservoir (Field X-E1, Field Y-D7 and Field Z-E2 reservoirs respectively) at depths between 10,000ft and 12,000ft below the surface. The genetic relatioships of the three fields has remained a matter for speculation. Water injection was started in Field Z in 1981, but was discontinued in 2001 due to inexplicable water losses and persistent steep drop in pressure. To account for this, some schools of thought have speculated that the three major reservoirs might possibly be connected. It was therefore imagined that if production in the more proximal Field X and Field Y caused pressure drop in the more distal Field Z, a common production strategy could be adopted for the three fields.
- Africa > Niger (1.00)
- Africa > Nigeria > Niger Delta (0.81)
- Phanerozoic > Mesozoic (1.00)
- Phanerozoic > Cenozoic > Neogene > Miocene > Lower Miocene (0.61)
- Geology > Geological Subdiscipline > Stratigraphy > Sequence Stratigraphy (1.00)
- Geology > Sedimentary Geology > Depositional Environment > Transitional Environment > Estuarine Environment (0.89)
- Geology > Sedimentary Geology > Depositional Environment > Continental Environment > Fluvial Environment (0.88)
- (3 more...)
- Geophysics > Borehole Geophysics (1.00)
- Geophysics > Seismic Surveying (0.68)
- North America > United States > Oklahoma > Northeast Oklahoma Platform Basin > Glenn Pool Field > Glenn Formation (0.99)
- North America > United States > Oklahoma > Northeast Oklahoma Platform Basin > Glenn Pool Field > Bartlesville Formation (0.99)
- North America > United States > Kentucky > Illinois Basin (0.99)
- (4 more...)