In the Freeman Field, located about 120km offshore southwestern Niger Delta at about 1300m water depth, 3D seismic attribute-based analogs, and structural and stratigraphic based geometric models are combined to help enhance and constrain interpretation. The objective of this research was to aid in the prospecting of Miocene to Pliocene Agbada Formation reservoirs in the deep offshore Niger Delta Basin. Multidisciplinary approaches – analysis of root-mean-square amplitude attribute, iterative integrated seismic interpretation and structural modeling, were employed in this study. Results reveal a massive northwest-southeast trending shale-cored detachment fold anticline containing numerous associated normal faults. This structure is interpreted to have been deformed by differential loading of the undercompacted, overpressured, and ductile Akata shale during syndepositional gravitational collapse of the Niger Delta slope. Crestal extension in the anticline resulted in a complex array of synthetic and antithetic normal faults, which include crossing-conjugate pairs. These conjugate structures could significantly affect permeability and reservoir performance. Crossing-conjugate faults have not previously been recognized in the Niger Delta, and similar structures may be present in other hydrocarbon-trapping structures in the basin. Also, the Miocene to Pliocene Agbada Formation reservoirs occur as part of a channelized fan system, mostly deposited as turbidites in an unconfined distributary environment, except one reservoir sand that occurs as channel sand within a submarine canyon that came across and eroded a previously deposited distributary fan complex, suggesting likely presence of prospective areas for hydrocarbon exploration southwest of the Freeman Field.
Presentation Date: Thursday, October 18, 2018
Start Time: 8:30:00 AM
Location: 210A (Anaheim Convention Center)
Presentation Type: Oral
This publication presents how the flow assurance strategies of a sandstone oil field were optimised after numerous production upsets. It also uses economics to justify facilities enhancement projects for flow assurance. Field F is an offshore oil field with 210 feet water depth and eight subsea wells tied back to a third party FPSO vessel.
Field F was shut down for turnaround maintenance in 2015. After the field was brought back online, one of the production wells (F5) failed to flow. An evaluation of the reservoir, well, and facilities data suggested that there was a gas hydrate blockage in the pipeline. A subsea intervention vessel was then hired to execute a pipeline pigging and clean-out operation, which removed the gas hydrate, and restored oil production from the F5 well. To minimise oil production losses due to flow assurance issues, the asset team evaluated the viability of installing a test pipeline and a second methanol umbilical as facilities enhancement projects.
The pipeline clean-out operation delivered 5400 barrels of oil per day production to the asset. The feasibility study suggested that installing a second methanol umbilical and a test pipeline are economically attractive. It is recommended that the new methanol umbilical is installed and used to guarantee flow from the F5 well and the planned infill production wells. The test pipeline should also be installed and used for new well clean ups, well testing, well sampling, water chemistry analysis, tracer evaluation, and production optimisation.
This paper presents failure diagnosis and flow assurance remediation steps in a producing oil field, and aids the justification of test pipeline and methanol umbilical capacity enhancement projects.
This publication presents the lessons learnt during an operation to remove a hydrate blockage and reinstate oil production from a deep water well offshore Nigeria. It also uses economics to justify facilities projects for hydrate prevention and flow assurance. Field D is a deep water field with sandstone reservoir formations, oil, and gas-cap gas at initial conditions. It has been developed with over 10 subsea production and injection wells tied back to a Floating, Production, Storage, and Offloading (FPSO) vessel.
Field D was shut down for turnaround maintenance during the summer of 2016. After the field was restarted, one of the production wells (D2) failed to flow. An evaluation of the pressure and temperature data suggested that the well had a tubing restriction. This was attributed to hydrate formation and blockage caused by limited methanol injection capacity.
A number of attempts were made to restart the well with no success. A subsea intervention vessel was then hired to execute a clean out intervention operation, which restored oil production from the D2 well. The intervention operation added 26 000 barrels of oil per day production to the asset.
To minimise hydrate blockage and oil production losses, the asset team completed feasibility studies to evaluate the viability of installing a second methanol umbilical and a test/service pipeline. These studied indicated that installing both facilities enhancement projects are economically attractive.
This publication presents the lessons learnt during hydrate formation in a producing oil field, and outlines practical methods that can be used to justify facilities enhancement projects.
One of the major challenges of Logging-While-Drilling (LWD) Magnetic Resonance data acquisition is its limited logging speed. Typically, LWD Magnetic Resonance is logged at speeds of approximately 20m/hr (65ft/hr). Higher logging speeds will substantially reduce the vertical resolution of the data and prevent full polarization of the Hydrogen Protons in the formation, thus, introducing errors in the measurement of total porosity, fluid fractions, and permeability.
The axial motion (rate of penetration) of the magnetic resonance data has multiple effects on the acquired data. The main effects occur to the data during the polarization time, and the amplitude of the echoes during the Carr-Purcell-Meiboom-Gill (CPMG) pulse sequence time. The effects on the amplitude are broadly referred to as the flow effects.
During the drilling of a well in the Niger Delta, an operator needed to save rig cost by increasing the Rate of Penetration (ROP) for LWD Magnetic Resonance from 20m/hr to 40m/hr. This increased ROP caused an overestimation of the total porosity from magnetic resonance.
A newly introduced correction technique enables the compensation of effects due to high ROP on magnetic resonance data. This ROP correction methodology compensates flow and polarization effects. Total porosity and fluid fractions were corrected, resulting also in an updated Magnetic Resonance permeability index. Validation of the technique was accomplished by an accurate match of the corrected total porosity to results from offset wells.
This paper demonstrates the effect of a high rate of penetration on acquired LWD data. Details of flow and polarization effects, and the procedure for correcting these effects, making the data useable and accurate, are also presented.
The Magnetic Resonance (MR) method is based on a magnetic interaction of the magnetic moments of nuclei and externally applied magnetic fields. In the field of Magnetic Resonance Well Logging, only the hydrogen nuclei are of interest. Hydrocarbon and water contain a large number of hyrodrogen nuclei. The hydrogen nuclei possess the strongest magnetic moment. The hydrogen nucleus is a proton. The proton has a mass, an angular momentum and a charge. A spinning charge creates a magnetic moment. This magnetic moment allows the interaction with magnetic fields.
Niger Delta stratigraphy is typified by intercalation of sand and shale in the Agbada formation deposited by series of cyclic sedimentation as a result of repeated transgressive and regressive events. The oldest sediment in the delta is the Akata formation, it is essentially shale overlain by the Agbada formation and the sandy Benin formation. The successive phases of the delta growth form transitory depo-belts that are bounded by mega-structural growth faults. Seismic imaging behind these major faults has consistently been a major challenge in de-risking prospects in the basin.
This paper enumerates the various efforts made to resolve fault shadow imaging challenges in the Niger Delta with successes achieved so far. Previous investigation carried out on fault shadow zone in the Niger Delta by Aikulola 2010 et, al resulted in the following observations.
I. Little or no residual move-out is evident on the PSDM gathers prior to stacking
II. Conflicting dip on the depth migrated gathers vis-à-vis the stacked section
III. Hockey sticks in gathers where prestack migrated gathers no longer assume hyperbolic shape thereby making it almost impossible to update the migration velocity with conventional measurement based on moveout
IV. Velocity perturbation does not necessarily fix the poor imaging challenge
V. Onset of overpressure often correlate with areas where imaging was poor
VI. Incorrect velocity alone is unlikely to cause the fault shadow
Also, recent work gave indication that the fault shadow zones are associated with multiples.
Leveraging on these observations and understanding this paper presents a different approach to tackling the imaging of the fault shadow zone with emphasis on the listed operations below
I. Better static solution and building a robust near surface velocity model.
II. Broadband noise attenuation.
III. Anisotropic model update.
IV. Advanced imaging.
Presentation Date: Wednesday, September 27, 2017
Start Time: 11:25 AM
Presentation Type: ORAL
George, C. O. (Department of Geological Sciences, Nnamdi Azikiwe University) | Thomas, S. W. (Chevron Nigeria Limited) | John, M. (Chevron Nigeria Limited) | Gani, A. (Chevron Nigeria Limited) | Emmanuel, A. K. (Department of Geological Sciences, Nnamdi Azikiwe University) | Norbert, A. E. (Department of Geological Sciences, Nnamdi Azikiwe University)
Post-drill pore pressure and fracture gradient analyses were carried out in an offshore hydrocarbon field, of Niger DeltaBasin, the G-field, using petrophysical logs, drilling parameters and pressure data. Four wells were analyzed and the results from the analysis will serve as a look back in building a Pre-Spud pore pressure and fracture gradient model for future drilling of exploration and production wells. The overburden gradient and normal compaction trend were generated based on an empirical formula. The pore pressure gradients were computed using the Eaton’s and Miller’s method respectively. Mud weights, drilling parameters and drilling events were used to calibrate the pore pressure gradients. Fracture gradient was computed using Mathews and Kelly’s method with pore pressure definitive, overburden gradient and effective stress ratio as the inputs. Based on the empirical methods, pressure transition zones were detected across the four wells with three (3) pressure ramps of magnitude of 1.23 ppg (Pound Per Gallon), 2.55ppg and 1.52ppg respectively. Pore pressure gradient model generated from the study revealed normally pressured zones at the shallower part of the unconfined section in all the wells within the range of 870 and 6273 feet TVD (True Vertical Depth) with an average shale pore pressure of 8.4ppg for Well 1,4715 and 9145 feet TVD with an average shale pore pressure of 8.5ppg for Well 2, 2614 and 7736 feet TVD with an average shale pore pressure of 8.39ppg for Well 3 and 4227 and 7972 feet TVD with an average shale pore pressure of 8.4ppg for Well 4. The top of the overpressured zones (>0.47 Psi/ft) (9ppg) were established across the four wells. The analysis of pore pressure of the field shows that the depth to the overpressured zones ranges from 7498 to 8859 feet TVD for Well 1,9825 and 13582 feet TVD for Well2, 7741 and 12264 TVD for Well 3 and 8307 and 12220 feet TVD for Well 4.
Technology advancements over the years have improved our understanding of the subsurface. This paper focuses on how integration of available geological and engineering datasets was used to de-risk the geological and petrophysical uncertainty of Reservoir B-1.1 in Oredo field in Niger Delta.
The oil reservoirs in this field experienced late fair aquifer support. However, the producing gas reservoirs exhibit volumetric drive behavior so far. Analysis of logs, production, pressure and PVT data were carried out. Fluid and material balance (analytical) models were built and fluid model was tested for validity. There was 80% difference between the material balance volume and the static model volume. The material balance volume is supported by historical Bottom Hole Pressure surveys and recent wireline formation test acquired from a sidetracked well in the field. This wireline formation test shows substantive pressure depletion across the reservoir of interest, which can be attributed to production activities from the existing conduit. Based on the geological analysis, there is no evidence of compartmentalization to account for the pressure and production behavior of the well producing from this reservoir. Sensitivity and uncertainty analysis on selected parameters were carried out on the base case geological/static model to validate the Hydrocarbon in Place volume for history matching and performance prediction.
The dynamic simulation run under uncertainty validated the material balance volume. This led to the revision of the petrophysical evaluation and update of the static model.
The complex nature of deep water sediments requires the use of a full field 3D static model to enable better understanding of the reservoir characteristics of the field. This study focuses on the 3D static modelling of the 458 reservoir in Botti field to facilitate field development. The Botti field is a partially appraised field located about 20km offshore Nigeria. A total of four wells have been drilled in the field and only two wells encountered the target reservoir. The depositional environment is mainly deep water slope channel sands with some submarine fans. The morphological uncertainties relating to the slope channel sands deposits, requires a detailed 3D static model which defines reservoir characteristics such as channel orientation, continuity and connectivity.
The experiences garnered in drilling deep wells in the Nigeria Delta Basin of Nigeria are presented herein. The referenced wells were drilled to the deep target series of gas and gas condensate reservoirs at depth range of 4900m - 5530m. The total volumes of the targeted reservoirs are about 60mmstb of oil and 1400bscf of gas. There were challenges of stuck pipes in phases through some depleted zones/reservoirs that were resolved through brainstorming with the production unit of the company. Other challenges encountered and highlighted are in hole stability, bit selection, Well control, HSE, rig efficiency and cost performance. Drilling the wells in sequence exploits the benefits of immediate application of gathered experiences from the previous wells.