Reservoir quality assessing and petroleum potential of Nepa horizon in Lena-Tunguska basin

Author(s):  
E. D. Sivkova ◽  
R. S. Sautkin

Reservoir layers were located within the Nepa horizon according to the log data interpretation of 26 wells. Porosity and gas saturation were calculated within these layers. The research provides an opportunity to determine reservoir potential of sediments and to identify further research lines.

2021 ◽  
Vol 11 (5) ◽  
pp. 2075-2089
Author(s):  
Mohamed Mahmoud Elhossainy ◽  
Ahmed Kamal Basal ◽  
Hussein Tawfik ElBadrawy ◽  
Sobhy Abdel Salam ◽  
Mohammad Abdelfattah Sarhan

AbstractThis paper presents different well log data interpretation techniques for evaluating the reservoir quality for the sandstone reservoir of the Alam El-Bueib-3A Member in Safir-03 well, Shushan Basin, Egypt. The evaluation of the available well log data for the Alam El-Bueib-3A Member in this well indicated high quality as oil-producing reservoir between depths 8108–8133 ft (25 ft thick). The calculated reservoir parameters possess shale volume less than or equal to 9% indicating the clean nature of this sandstone interval, water saturation values range from 10 to 23%, and effective porosity varies between 19 and 23%. Bulk volume of water is less than 0.04, non-producing water (SWirr) saturation varies between 10 and 12%, and permeability ranges from 393 to 1339 MD reflecting excellent reservoir quality. The calculated BVW values are less than the minimum (BVWmin = 0.05) reflecting clean (no water) oil production, which was confirmed through the drill stem test (DST). The relative permeabilities to both water and oil are located between 0.01–0 and 1.0–0.5, respectively. The water cut is fairly low where it ranges between 0 and 20%. Additionally, the water saturation values are less than the critical water saturation (Scw = 29.5%) which reflects that the whole net pay will flow hydrocarbon, whereas the water phase will remain immobile. This was confirmed with reservoir engineering through the DST.


2015 ◽  
Vol 3 (1) ◽  
pp. SA159-SA166 ◽  
Author(s):  
Larry Jacobson ◽  
Venkataraman Jambunathan ◽  
Zhipeng Liu ◽  
Weijun Guo

Recently developed multidetector pulsed-neutron tools (MDPNTs — a term describing a pulsed-neutron tool with at least three detectors) can provide three-phase formation fluid analysis in cased wells. These tools are 43 mm (1 11/16 in.) or 54 mm (2 1/8 in.) in diameter and can be logged in or below most tubing sizes. We reviewed traditional oil- and water-saturation techniques as well as indirect gas-saturation techniques, and we compared them with recently developed direct gas-saturation techniques, now available from MDPNTs. A log example developed the data verification and interpretation process. The interpretation process was divided into two parts: First, we verified the log data quality and second, we applied a newly developed gas model to the log data providing gas saturation without any reliance on the previously determined oil and water saturation.


2018 ◽  
Vol 7 (2) ◽  
pp. 200-213
Author(s):  
Muhammad Nur Ali Akbar ◽  
Septian Tri Nugraha

Abstract The petrophysical analysis is the crucial task for evaluating the quality of unconventional organic-rich shale and tight gas reservoirs. The presence of organic matter and the ultra-tight with over complex pore system have remained a lack of understanding of how to evaluate the extensive parameters of porosity considering organic content, gas saturation, organic richness, brittleness index, and sweet spot interval by only using conventional log. Therefore, this study offers effectively applied techniques and better analysis for interpreting these parameters by maximizing and integrating geological, geochemical, rock mechanical and engineering data. In general, the field data used in this study are from the first dedicated well for source rock exploration in the North Sumatra Basin, Indonesia. The developed method was derived by using conventional log. All interpretation results were validated by laboratory data measurements of routine and special core analysis, petrography, total organic carbon (TOC) and organic maturation, and brittleness index (BI) calculation. Moreover, the high quality of NMR log data was used as well to ensure our developed techniques present good estimations. Briefly about the methods, we started to determine the total and effective porosity based on the density log by including the presence of organic matter and multi-mineral analysis in these estimations. Then, we used the revised water saturation-TOC of water saturation while the TOC was predicted in advance by averaging three results from the correlation of TOC-Density, modified CARBOLOG and Passey’s ΔlogR methods. Equally important, in order to obtain the reliable gas saturation prediction, we used saturation exponent (n), cementation factor (m), and the tortuosity factor (a) parameters which obtained from laboratory measurement of formation resistivity factor and resistivity index (FFRI). In addition, the brittleness index was predicted based on sonic log data. Finally, all parameters needed for determining gas shale sweet spot have been made. Then, we developed a way to evaluate the sweet spot interval by using K-mean clustering. In conclusion, this clustering result properly follows the shale quality index parameters which consist of organic richness and maturation, brittleness index, the storage capacity of porosity and gas saturation. This study shows that these petrophysical applied techniques leads us to interpret the best position of shale interval to be developed with a simple, fast, and accurate prediction way. Furthermore, as a novelty, this method can be used as rock typing method and obviously can reduce uncertainty and risks in organic-rich shale exploration.


2001 ◽  
Vol 41 (1) ◽  
pp. 415 ◽  
Author(s):  
D.C. Barr ◽  
A.F. Kennaird ◽  
J. Fowles ◽  
N.G. Marshall ◽  
V.L. Cutten

A recent geological study, integrating sedimentological core-derived descriptions with ichnofacies, high resolution biostratigraphy and wireline log data, establishes the lateral continuity of reservoir sandstones in the Laminaria Formation. By defining a hierarchy of bedding surfaces and correlating this hierarchy with major correlation surfaces, and lateral and vertical facies patterns, it was possible to identify genetically related sediment packages between 12 wells in the study area.The Laminaria Formation is interpreted to have been deposited on a tide and storm-influenced marine shelf, and was strongly influenced by fluctuations in sea level. The formation consists of a series of progradational parasequences, each dominated by good quality, fine- to medium-grained sandstone. These sandstones are believed to have formed as subaqueous dunes or sand banks, exhibiting blanket-like geometry over much of the area. Several sandstones are capped by thin, intraclast-rich layers that mark transgressive surfaces of erosion. These surfaces can be traced across the study area and, therefore, act as important correlative markers.Evidence of gradual transgression, which ultimately led to the drowning of the system, is seen near the top of the formation. Clay content increases upward, while grain size and bedding thickness generally decrease. However, several thin, laterally extensive, medium- to coarse-grained sandstones exist, improving reservoir potential in this part of the formation.The results of this study are being used to estimate reserves and assess reservoir performance, and will serve as a basis for future geological and petrophysical modelling work.


2009 ◽  
Vol 49 (2) ◽  
pp. 600
Author(s):  
Brad Field ◽  
Jan Baur ◽  
Kyle Bland ◽  
Greg Browne ◽  
Angela Griffin ◽  
...  

Hydrocarbon exploration on the East Coast of the North Island has not yet yielded significant commercial reserves, even though the elements of a working petroleum system are all present (Field et al, 1997). Exploration has focussed on the shallow, Neogene part of the succession, built up during plate margin convergence over the last ∼24 million years. Convergent margins are generally characterised by low-total organic carbon (TOC) source rocks and poor clastic reservoir quality due to poor sorting and labile grains. However, the obliquely-convergent Hikurangi subduction margin of the East Coast has high TOC source rocks that pre-date the subduction phase, and its reservoir potential, though variable, has several aspects in its favour, namely: deep-water rocks of high porosity and permeability; preservation of pore space by overpressure; the presence of fractured reservoirs and hybrid reservoirs, where low clastic permeability is enhanced by fractures. The East Coast North Island is a Neogene oblique subduction margin, with Neogene shelf and slope basins that developed on Late Cretaceous-Paleogene passive margin marine successions. The main hydrocarbon source rocks are Late Cretaceous and Paleocene and the main reservoir potential is in the Neogene (Field et al, 2005). Miocene mudstones with good seal potential are common, as is significant over-pressuring. Neogene deformation controlled basin development and accommodation space and strongly-influenced lateral facies development and fractured reservoirs. Early to Middle Miocene thrusting was followed by later Neogene extension (e.g. Barnes et al 2002), with a return to thrusting in the Pliocene. Local wells have flow-tested gas shows.


Sign in / Sign up

Export Citation Format

Share Document