In-situ Stress Determination for Well Planning in the Niger Delta

Eghekaire Oghenetejiri, T.K Abam, Animia. A. Wordu

Abstract


During drilling, production and injection activities, great disturbances occur in the rock formation which causes change in the initial equilibrium of rock formation, altering the mechanical conditions and also virgin in-situ stresses. These disturbances which occur in the rock formation lead to redistribution of stresses around the wellbore, which may negatively affect the drilling, completion operations and also production efficiency leading to increased cost and delays in operations. Wellbore failure accounts for more than 10% of non productive time in drilling and other related issues in Niger Delta. This research work evaluates some rock mechanical properties critical to wellbore stability, both during drilling and production, using caliper, gamma ray, density, sonic and true resistivity logs from a well in the Niger Delta. These logs were run into software and the investigated stratigraphic units are the typical interlayered, shales and sandstones of the Agbada formation. The lithology was found to consist of 20 sand sections and 20 shale sections. It was also found that wellbore breakouts were predominant in shales and weak shaly sandstones across the lithologic units. Mud weight window varies between 0-8.7ppg with depth due to heterogeneity and anisotropy in the formation. The friction angle at depth 8461ft is 14.90 and generally in the NE direction. The vertical stress ranges from 0 to 5260.917 psi/ft, the minimum horizontal stress range from 963.8206 psi at 6142.317ft to 5059.214 psi at 11615.95ft. The maximum horizontal stress varied from 6142.317ft to 7111.654ft and remained constant from there onto 11615.95ft with a value of -0.2138psi.  The hydrostatic pressure was found to increase with depth due to increase weight of overburden pressure. Tensile strain was also seen to be higher in shales than sand as a result of their unstable nature. Significant variations in properties between the cap rocks and the reservoir sand units in the well were also observed with the cap rock having an average of 0.2 Poisson ration and bulk moduli of 466.1 MPa. These data will be useful in well planning for other wells around the case study area as well as the field at large.


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