Downhole Estimation of Relative Permeability With Integration of Formation-Tester Measurements and Advanced Well Logs
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Cited by 3 publications
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Deepwater turbidite reservoirs have always presented several reservoir characterization challenges. Determining the complex architecture of the sand bodies, correlating them across multiple wells in the structure, and defining the sedimentological facies to determine the reservoir vertical communication and boundaries are some challenges in these Gulf of Mexico (GOM) turbidites. Other formation-related challenges of turbidite reservoir exploration and development include understanding reservoir rock quality and compartmentalization, as well as the identification of fluids. Deepwater exploration and development require innovative, cost effective evaluation technologies—technologies that help manage ultradeep and high-pressure environments. Having a detailed description of reservoir properties, fluids characterization, and a determination of the reservoir connectivity are crucial for understanding the reservoir and optimizing the field development plan. This study describes the wireline formation tester (WFT) operations performed in a harsh environment [ultradeepwater subsalt formation (> 32,000 ft) and high pressure (> 25,000 psi)] to obtain pressure data, establish gradients, evaluate vertical connectivity using vertical interference tests (VITs), check for compositional variation in different oil columns, and obtain clean formation fluid samples. Downhole fluid analysis was performed to help ensure the quality of formation samples and determine the fluid compositional analysis in real time during pumpout. To obtain high quality fluid samples while minimizing costs, an innovative technology—namely, a focused sampling probe—was used, eliminating the need for long pumpouts. Representative formation fluid samples were captured from three sample depths in approximately two hours per sample depth with minimum oil-based mud (OBM) contamination (< 5%). All the available openhole log data were integrated to understand the reservoir before running the WFT. Optimizing pressure and sampling depths (most representative intervals) can help reduce uncertainty when determining the number of pressure and sample points in the reservoir. Formation mobility, near-wellbore skin damage, reservoir pressure, downhole compositional fluid analysis, and reservoir connectivity were evaluated in a unique and challenging environment. Reservoir connectivity results from formation testing show good alignment with the presence of fractures and other sedimentary features from borehole image data. A similar methodology can be extended to other deepwater turbidite reservoirs in the GOM.
Deepwater turbidite reservoirs have always presented several reservoir characterization challenges. Determining the complex architecture of the sand bodies, correlating them across multiple wells in the structure, and defining the sedimentological facies to determine the reservoir vertical communication and boundaries are some challenges in these Gulf of Mexico (GOM) turbidites. Other formation-related challenges of turbidite reservoir exploration and development include understanding reservoir rock quality and compartmentalization, as well as the identification of fluids. Deepwater exploration and development require innovative, cost effective evaluation technologies—technologies that help manage ultradeep and high-pressure environments. Having a detailed description of reservoir properties, fluids characterization, and a determination of the reservoir connectivity are crucial for understanding the reservoir and optimizing the field development plan. This study describes the wireline formation tester (WFT) operations performed in a harsh environment [ultradeepwater subsalt formation (> 32,000 ft) and high pressure (> 25,000 psi)] to obtain pressure data, establish gradients, evaluate vertical connectivity using vertical interference tests (VITs), check for compositional variation in different oil columns, and obtain clean formation fluid samples. Downhole fluid analysis was performed to help ensure the quality of formation samples and determine the fluid compositional analysis in real time during pumpout. To obtain high quality fluid samples while minimizing costs, an innovative technology—namely, a focused sampling probe—was used, eliminating the need for long pumpouts. Representative formation fluid samples were captured from three sample depths in approximately two hours per sample depth with minimum oil-based mud (OBM) contamination (< 5%). All the available openhole log data were integrated to understand the reservoir before running the WFT. Optimizing pressure and sampling depths (most representative intervals) can help reduce uncertainty when determining the number of pressure and sample points in the reservoir. Formation mobility, near-wellbore skin damage, reservoir pressure, downhole compositional fluid analysis, and reservoir connectivity were evaluated in a unique and challenging environment. Reservoir connectivity results from formation testing show good alignment with the presence of fractures and other sedimentary features from borehole image data. A similar methodology can be extended to other deepwater turbidite reservoirs in the GOM.
Integrated Fracture Performance and Formation Damage Assessment to Enhance Well Production in the Hassi Messaoud Field, Algeria: Case Study
This paper discusses the causes of performance failure of a well in the Hassi Messaoud field in Algeria that was fracture stimulated but did not achieve the expected production increase, and it discusses alternative methods to increase well production by integrating geology and petrophysics with production and well-test data. The well was perforated in sand B and in the upper section of sand C. It was initially tested at 5.07 m3/h (765 B/D), but within three months, production declined to 1.99 m3/h (300 B/D). Early studies suggested that the rapid decline was probably caused by near-wellbore formation damage during drilling. A fracturing program was designed to help remove well damage and restore flow capacity; however, negligible production increase was observed following the hydraulic fracturing. Initially, damage on the fracture face and uncleaned fracturing fluid were the suspected causes of the ineffective fracture stimulation. A new pressure-buildup test was performed to assess the effectiveness of the fracture stimulation, and detailed analyses indicated that the small reservoir size might have been the cause of the rapid pressure decline. The fracturing design was based on pressure data from the initial drillstem test (DST) at 388.9 kg/cm2 (5,531 psi). A post-fracture pressure-buildup test revealed that reservoir pressure had declined to 233.2 kg/cm2 (3,317 psi) after only producing 6901 m3 (43,406 bbl). The pressure-buildup analysis detected a fourth boundary that was not mapped during the original three-dimensional (3D) seismic survey. This fault reduced the well drainage area by a factor of four and was the cause of the rapid pressure decline during production. A recent seismic survey refined the geological map of the entire reservoir and confirmed the presence of this fault. Petrophysical analysis of sand C showed higher-quality rock than sand B; however, the resistivity decreased with increasing sand C depth, suggesting the presence of water. Lithology analysis confirmed that the decrease in resistivity was resulted from higher clay content and clay-bound water. Offset wells also confirmed that the oil-water contact (OWC) was approximately 70 m (229.7 ft) below the bottom of this well. Well productivity could have been significantly higher if the entire sand B pay was initially completed. To compensate for low-formation pressure, a gas-lift optimization procedure was performed to lift the fluid to surface with an initial production of 2.14 m3/h (323 STB/D). After two years, the reservoir pressure in this bounded section declined to 169 kg/cm2 (2,404 psi). This paper discusses an integrated approach to increase oil production from a well penetrating a geologically challenging environment. Integration of geology, petrophysics, seismic, production modeling, and gas lift with proper data acquisition helped prevent abandonment of this well, leaving behind potential reserves. This paper also discusses a case study in which a false-formation damage diagnosis could have led to reservoir mismanagement.
Scale Up of Pore-Network Models into Reservoir Scale: Optimization of Inflow Control Devices Placement
Summary Improvements to more advanced tools, such as inflow control devices (ICDs), create a high drawdown regime close to wellbores. Gas liberation within the formation occurs when the drawdown pressure is reduced below the bubblepoint pressure, which in turn reduces oil mobility by reducing its relative permeability, and potentially reducing oil flow. The key input in any reservoir modeling to compare the competition between gas and liquid flow toward ICDs is the relative permeability of different phases. Pore-network modeling (PNM) has been used to compute the relative permeability curves of oil, gas, and water based on the pore structure of the formation. In this paper, we explain the variability of pore structure on its relative permeability, and for a similar formation and identical permeability, we explain how other factors, such as connectivity and throat radius distribution, can vary the characteristic curves. By using a boundary element method, we also incorporate the expected relative permeability and capillary pressure curves into the modeling. The results show that such variability in the pore network has a less than 10% impact on production gas rates, but its effect on oil production can be significant. Another important finding of such modeling is that providing the PNM-created relative permeabilities may provide totally different direction on setting the operational constraints. For example, in the case studied in this paper, PNM-created relative permeability curves suggest that a reduction of flowing bottomhole pressure (FBHP) increases the oil rate, but for the case modeled with a Corey correlation, changes in FBHP will not create any uplift. The results of such work show the importance of PNM in well completion design and probabilistic analysis of the performance, and can be extended based on different factors of the reservoir in future research. Although PNM has been widely used to study the multiphase flow in porous media in academia, the application of such modeling in reservoir and production engineering is quite narrow. In this study, we develop a framework that shows the general user the importance of PNM simulation and its implementation in day-to-day modeling. With this approach, the PNM can be used not just to provide relative permeability or capillary pressure curves on a core or pore- scale, but to preform simulations at the wellbore or reservoir scale as well to optimize the current completions.
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