Downhole Estimation of Relative Permeability With Integration of Formation-Tester Measurements and Advanced Well Logs
- Hamid Hadibeik (Halliburton) | Mehdi Azari (Halliburton) | Mahmoud Kalawina (Halliburton) | Sandeep Ramakrishna (Halliburton) | Sami Eyuboglu (Halliburton) | Waqar Khan (Halliburton) | Mona Al-Rushaid (Kuwait Oil Company) | Hamad Al-Rashidi (Kuwait Oil Company) | Munir Ahmad (Kuwait Oil Company)
- Document ID
- Society of Petrophysicists and Well-Log Analysts
- Publication Date
- April 2018
- Document Type
- Journal Paper
- 234 - 244
- 2018. Society of Petrophysicists & Well Log Analysts
- 3 in the last 30 days
- 144 since 2007
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Reservoir relative permeability as a function of saturation is critical for assessing reservoir hydrocarbon recovery, selecting the well-completion method, and determining the production strategy. It is a key input to reservoir simulation for predicting lifetime production of a well. Estimation of relative permeability curves at reservoir conditions is also a crucial task for successful reservoir modeling and history matching of production data. The relative permeability data estimated from core analysis may cause concern regarding representativeness, and adjustments are typically necessary for successful production forecasting. This paper proposes a new method to obtain relative permeability curves with downhole pressure-transient analysis of mini-drillstem tests (mini-DSTs) and well-log-derived saturations.
The new approach was based on performing mini-DSTs in the free water, oil, and oil-water transition zones. Analyses of the mini-DST buildup tests provided absolute formation permeability, endpoints of relative permeability to both oil and water, and curvature of the relative permeability data. Additionally, porosity and resistivity logs were used to determine irreducible water, residual oil, and transition zone saturations. Combining all of these downhole measurements provided the relative permeability curves.
When multiphase fluids flow in a reservoir, the flow rate of each phase depends on the effective permeability of that phase (Alkafeef et al., 2016). Effective permeability is obtained from absolute permeability of a reservoir multiplied by the relative permeability. Although absolute permeability is a function of reservoir pore geometry and does not change with fluid type, relative permeability is a fluid-dependent parameter and mainly depends on fluid saturation, pore geometry, viscosity, and surface tension (Goda and Behrenbruch, 2004).
|File Size||2 MB||Number of Pages||11|