Prediction of Fracture Pressure in Niger Delta Deep Offshore

During drilling operations, it is essential to keep the wellbore pressure within the maximum value of the fracture pressure and minimum value of the pore pressure of the formation. To handle this challenge, the fracture pressure of the formation must be known as it is significant to determining the mud window design. This study developed a correlation that could predict the formation fracture pressure in the Niger Delta deep offshore field. Two different fields were considered for this model named Field 1 and 2. From these fields, fracture pressure data were gotten from 21 wells during leak off test (LOT) at different casing shoe depths. While carrying-out the analysis of data, assumptions were made that the formations throughout the Niger Delta basin obeys the principle of horizontality. Also, that the fracture pressure at same depth is uniform with the pressure at other location in the Delta. Scatter plot was used as the tool for the data analysis. A line of best fit was drawn to arrive at the correlation. This correlation has an R2 coefficient values of 0.9969. In conclusion, the correlation gotten from this study for predicting fracture pressure has shown to align with some data sets from the Niger Delta fields with very little variation. This can be used for planning of further drilling operations in the Niger Delta to make it easier, faster and more economical.

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The Niger Delta basin fracture pressure prediction

Environmental Earth Sciences ◽

10.1007/s12665-020-09081-5 ◽

2020 ◽

Vol 79 (13) ◽

Author(s):

Olalere Oloruntobi ◽

Omolola Falugba ◽

Oluchi Ekanem-Attah ◽

Chukwunweike Awa ◽

Stephen Butt

Keyword(s):

Niger Delta ◽

Fracture Pressure ◽

Niger Delta Basin

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Determining Fracture Pressure Gradients from Well Logs

International Journal of Advanced Geosciences ◽

10.14419/ijag.v8i1.29162 ◽

2020 ◽

Vol 8 (1) ◽

pp. 5

Author(s):

Udo K. I ◽

George N. J ◽

Akankpo A. O ◽

Azuoko G. B ◽

Aka M.U

Keyword(s):

Niger Delta ◽

Well Logs ◽

Pressure Gradients ◽

Seal Failure ◽

Fracture Pressure ◽

Shear Wave Velocities ◽

Pore Pressures ◽

Sonic Log ◽

Drilling Operations ◽

Sonic Logs

Fracture pressure gradient is one of the essential parameters used in determining mud weight profiles during drilling operations. We have determined fracture pressure gradients from well logs obtained from three producing wells in Onshore Niger Delta using an empirical model. Key logs needed for the prediction were conditioned and quality controlled to meet the standard required for reliable results. The true vertical stress, normal compaction trend and compressional shale velocity trends were generated from the logs (density and sonic logs). Poison’s ratio was obtained from compressional and shear wave velocities derived from sonic log. Pore pressures in the three wells were then predicted using Eaton’s Method. The predicted pore pressures, overburden pressures and poison’s ratio were used to determine fracture pressures using Ben Eaton’s Model. Results showed that there is a suitable drilling margin at all depths only in well G-005. Drilling well A-001 to a depth of 10962.81 ft and K-001 to a depth of 12626.9 ft will fracture the formations because the fluid pressures at those depths approximate the fracture pressures of 8536.7psi and 9506 psi with corresponding gradients of 0.78 psi/ft and 0.75 psi/ft respectively. The implication is that drilling deeper in the field will results in very low seal capacity magnitudes, thereby presenting a higher risk of top-seal failure.

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Consistency of nonlinear interacting ghost dark energy with recent observations

International Journal of Modern Physics D ◽

10.1142/s0218271817501243 ◽

2017 ◽

Vol 26 (11) ◽

pp. 1750124 ◽

Cited By ~ 4

Author(s):

E. Ebrahimi ◽

H. Golchin ◽

A. Mehrabi ◽

S. M. S. Movahed

Keyword(s):

Dark Energy ◽

Observational Data ◽

Nonlinear Interaction ◽

Acoustic Oscillation ◽

Joint Analysis ◽

Data Sets ◽

Dark Energy Density ◽

Ghost Dark Energy ◽

Interaction Terms ◽

Best Fit

In this paper, we investigate ghost dark energy model in the presence of nonlinear interaction between dark energy and dark matter. We also extend the analysis to the so-called generalized ghost dark energy (GGDE) which [Formula: see text]. The model contains three free parameters as [Formula: see text] and [Formula: see text] (the coupling coefficient of interactions). We propose three kinds of nonlinear interaction terms and discuss the behavior of equation of state, deceleration and dark energy density parameters of the model. We also find the squared sound speed and search for signs of stability of the model. To compare the interacting GGDE model with observational data sets, we use more recent observational outcomes, namely SNIa from JLA catalog, Hubble parameter, baryonic acoustic oscillation and the most relevant CMB parameters including, the position of acoustic peaks, shift parameters and redshift to recombination. For GGDE with the first nonlinear interaction, the joint analysis indicates that [Formula: see text], [Formula: see text] and [Formula: see text] at 1 optimal variance error. For the second interaction, the best fit values at [Formula: see text] confidence are [Formula: see text], [Formula: see text] and [Formula: see text]. According to combination of all observational data sets considered in this paper, the best fit values for third nonlinearly interacting model are [Formula: see text], [Formula: see text] and [Formula: see text] at [Formula: see text] confidence interval. Finally, we found that the presence of interaction is compatible in mentioned models via current observational datasets.

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Managing Wellbore Stability Window and Well Integrity by Adjusting the Tight Margin to Successfully Drill through Naturally Fractured Zone Onshore Niger Delta

10.2118/207189-ms ◽

2021 ◽

Author(s):

Bassey Akong ◽

Samuel Orimoloye ◽

Friday Otutu ◽

Akinwale Ojo ◽

Goodluck Mfonnom ◽

...

Keyword(s):

Niger Delta ◽

Wellbore Stability ◽

Rock Properties ◽

Failure Behavior ◽

Natural Fractures ◽

Gas Well ◽

Well Integrity ◽

Trajectory Formation ◽

Naturally Fractured ◽

Drilling Operations

Abstract The analysis of wellbore stability in gas wells is vital for effective drilling operations, especially in Brown fields and for modern drilling technologies. Tensile failure mode of Wellbore stability problems usually occur when drilling through hydrocarbon formations such as shale, unconsolidated sandstone, sand units, natural fractured formations and HPHT formations with narrow safety mud window. These problems can significantly affect drilling time, costs and the whole drilling operations. In the case of the candidate onshore gas well Niger Delta, there was severe lost circulation events and gas cut mud while drilling. However, there was need for a consistent adjustment of the tight drilling margin, flow, and mud rheology to allow for effective filter-cake formation around the penetrated natural fractures and traversed depleted intervals without jeopardizing the well integrity. Several assumptions were validly made for formations with voids or natural fractures, because the presence of these geological features influenced rock anisotropic properties, wellbore stress concentration and failure behavior with end point of partial – to-total loss circulation events. This was a complicated phenomenon, because the pre-drilled stress distribution simulation around the candidate wellbore was investigated to be affected by factors such as rock properties, far-field principal stresses, wellbore trajectory, formation pore pressure, reservoir and drilling fluids properties and time without much interest on traversing through voids or naturally fractured layers. This study reviews the major causes of the severe losses encountered, the adopted fractured permeability mid-line mudweight window mitigation process, stress caging strategies and other operational decisions adopted to further salvage and drill through the naturally fractured and depleted intervals, hence regaining the well integrity by reducing NPT and promoting well-early-time-production for the onshore gas well Niger Delta.

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Lithofacies Analysis and Qualitative Minerology of the Sediments of #3 Well in the Greater Ughelli Depobelt, Niger Delta Basin

Journal of Scientific Research ◽

10.3329/jsr.v13i2.49948 ◽

2021 ◽

Vol 13 (2) ◽

pp. 601-610

Author(s):

K. Itiowe ◽

R. Oghonyon ◽

B. K. Kurah

Keyword(s):

Physical Properties ◽

Clay Minerals ◽

Niger Delta ◽

Reservoir Quality ◽

X Ray Diffraction ◽

X Ray ◽

Sandy Shale ◽

Heterogeneous Nature ◽

Niger Delta Basin ◽

Shaly Sandstone

The sediment of #3 Well of the Greater Ughelli Depobelt are represented by sand and shale intercalation. In this study, lithofacies analysis and X-ray diffraction technique were used to characterize the sediments from the well. The lithofacies analysis was based on the physical properties of the sediments encountered from the ditch cuttings. Five lithofacies types of mainly sandstone, clayey sandstone, shaly sandstone, sandy shale and shale and 53 lithofacies zones were identified from 15 ft to 11295 ft. The result of the X-ray diffraction analysis identified that the following clay minerals – kaolinite, illite/muscovite, sepiolite, chlorite, calcite, dolomite; with kaolinite in greater percentage. The non-clay minerals include quartz, pyrite, anatase, gypsum, plagioclase, microcline, jarosite, barite and fluorite; with quartz having the highest percentage. Therefore, due to the high percentage of kaolinite in #3 well, the pore filing kaolinite may have more effect on the reservoir quality than illite/muscovite, chlorite and sepiolite. By considering the physical properties, homogenous and heterogeneous nature of the #3 Well, it would be concluded that #3 Well has some prospect for petroleum and gas exploration.

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Sedimentary facies and petrographic analyses of Miocene nearshore deposits, Central Swamp Depobelt, onshore Niger Delta Basin: implications for reservoir quality

Journal of Sedimentary Environments ◽

10.1007/s43217-021-00076-1 ◽

2021 ◽

Author(s):

Joseph Nanaoweikule Eradiri ◽

Ehimare Erhire Odafen ◽

Ikenna Christopher Okwara ◽

Ayonma Wilfred Mode ◽

Okwudiri Aloysius Anyiam ◽

...

Keyword(s):

Niger Delta ◽

Sedimentary Facies ◽

Reservoir Quality ◽

Petrographic Analyses ◽

Niger Delta Basin

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Surviving the Low Oil Price Cycle While Increasing Production Through Best Practices in Workover and Drilling Operations; Case Study of a Marginal Field in Niger Delta, Nigeria

10.2118/193477-ms ◽

2018 ◽

Author(s):

Longfellow Oghale Atakele ◽

Osahon Noruwa Airhis ◽

Ntietemi Ekpo Etim ◽

Fisayo Jordan Ipoola ◽

John Osadebe Anim ◽

...

Keyword(s):

Best Practices ◽

Niger Delta ◽

Oil Price ◽

Drilling Operations ◽

Marginal Field

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

International Journal of Advanced Geosciences ◽

10.14419/ijag.v5i1.7456 ◽

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.

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