clastic reservoirs
Recently Published Documents


TOTAL DOCUMENTS

257
(FIVE YEARS 47)

H-INDEX

11
(FIVE YEARS 3)

Author(s):  
Ahmed A. Radwan ◽  
Bassem S. Nabawy

AbstractIn this study, it is aimed to characterize the Early pliocene sandstone (EP-SD) and the Late Miocene-Early Pliocene Mangaa sandstone reservoirs and the efficiency of their sealing cap rocks using the petrographical and petrophysical data of these sandstone zones in northern Taranaki basin, New Zealand. The prospective potential reservoirs were studied using impregnated thin sections, XRD data analysis, and well log data (self-potential, gamma-ray, sonic, density, neutron, shallow\deep resistivity and PEF) to characterize the reservoir zones, in addition to Mercury intrusion capillary pressure data (MICP) to check the efficiency of some potential seals. The EP-SD and the Mangaa sandstone units are typically poorly consolidated very fine sandstone to siltstone, with porosities averaging 25%. The sands are composed of quartz (38.3–57.4%), with common feldspars (9.9–15.2% plagioclase, and 2.7–6.3% K-feldspars) and up to 31.8% mica. In Albacore-1 well to the north of the Taranaki Basin, the Mangaa formation includes three separate for each of the EP-SD zones (EP-SD1, EP-SD2, and EP-SD3), and the Mangaa sequence (Mangaa-0, Mangaa-1, and Mangaa-2). The thin section studies indicate that, the studied samples are grouped into greywackes, arenites and siltstone microfacies with much lithic fragments and feldspars, sometimes with glauconite pellets. From the XRD data, it is achieved that the mineral composition is dominated by quartz, mica/illite, feldspars, and chlorite. The petrophysical investigation revealed absence of pay zones in the EP-SD zones, and presence of thin pay zone with net thickness 5.79 m and hydrocarbon saturation of about 25.6%. The effective porosities vary between 23.6 and 27.7%, while the shale volume lies between 12.3 and 16.9%. Although the shale content is relatively low, the relatively high API (50–112 API of average 75 API) is contributed by the relatively high K-feldspar content and intercalations with thin siltstone and muddy siltstone beds. Sealing units include the intra-formational seals within the Mangaa sequence, mudstones and fine grained units overlying the Mangaa and further intra-formational mudstones, within the shallower EP-SD units. The efficiency of these seals indicates the capability to trap 16.4–40.6 m gas or 17.4–43.0 m oil which is relatively low in correlation with their efficiency in the central parts of the Taranaki Basin Overlying the primary seals, mudstones of the Giant Foresets Formation provide additional regional seal.


2022 ◽  
pp. 105520
Author(s):  
Dongdong Hong ◽  
Jian Cao ◽  
Xuguang Guo ◽  
Baoli Bian ◽  
Hailei Liu

2021 ◽  
Vol 9 ◽  
Author(s):  
Liang Chen ◽  
Hancheng Ji ◽  
Nansheng Qiu ◽  
Liang Zhang

The grain sizes of clastic rock sediments serve as important depositional indicators that are significant in sedimentology and petroleum geology studies. Generally, gamma ray, spontaneous-potential and resistivity well logs are utilized to qualitatively characterize variations in sediment grain size and determine the lithology in clastic reservoirs. However, grain size analysis of modern sedimentary samples collected from active rivers and deltas indicates that the percentage of fine depositional component has a logarithmic relationship with the average grain size in delta and river systems. Using the linear relationship to process the lithology interpretation, siltstones or mudstone is likely to be interpreted as sandstone. Therefore, a logarithmic conversion formula was built up between the gamma ray logs and measured grain size for the second member of the Xujiahe Formation of Anyue Area in the Sichuan Basin. Using the formula, the average grain size and lithology of the exploration wells were determined for the interest intervals. Furthermore, the calculated grain size gives a better understanding of the controlling factors of hydrocarbon-bearing reservoirs in the study area.


2021 ◽  
Author(s):  
Suria Amalia Suut ◽  
Mahmood Khamis Al Kalbani ◽  
Issa Quseimi ◽  
Abdullah Gahaffi ◽  
Arjen Wielaard ◽  
...  

Abstract This paper summarises a ONE development success story of reviving a mature brownfield in South of Oman, Field β, just within ONE year through collaboration between different disciplines, comprehensive data analysis, optimising and recompletion of existing wells. Field β, comprised of multi-stacked clastic reservoirs, was put on stream in 1980s and peaked in early 1990s. Pilot water injection started in 1993 and full field water flooding continued in 1997. After more than 35 years since start of production, one can say the field was already in the tail end of its life. It had been stabilizing at low rate after 25 years and starting to decline further and at some point was one of the potential candidates to be decommissioned. A new FDP (FDP18) for part of the field was delivered in 2018 with the first well drilled at the end of that year. In 2019, despite drilling further wells on the FDP18, production was declining and was at 2018 rate towards the year end. Intensive data analysis and integrated reservoir reviews per reservoir layers were actively performed and new opportunities and data gathering were identified. FDP18 wells from 2019 onwards were then deepened to also acquire log data over deeper than the target reservoirs. Further synergy between asset and exploration teams also instigated in new discoveries including oil in shallower carbonate reservoirs, which were logged and sampled when drilling the FDP18 wells. Declining production, low oil price and COVID-19 crisis that hit 2020 challenged the team to be more resilient and with ONE development mindset between development and WRFM team, also between asset and exploration team, existing long-term closed in and very low productivity wells were utilised to tap these new opportunities. As a result, the field production has been increased by more than double, highest since 10 years ago, with a potential of triple its production rate, all achieved through optimizing and recompletion of existing wells within 1 year, at a very attractive low UTC.


2021 ◽  
pp. 105508
Author(s):  
Dongming Zhi ◽  
Xun Kang ◽  
Zhijun Qin ◽  
Yong Tang ◽  
Jian Cao ◽  
...  

2021 ◽  
pp. 1-14
Author(s):  
Elizaveta Shvalyuk ◽  
Alexei Tchistiakov ◽  
Alexandr Kalugin

Summary The main objective of this study was to provide rock typing of the producing formation based on high-resolution computed tomography (CT) scanning and nuclear magnetic resonance (NMR) data in combination with routine core analyses results. The target formation is composed of a shallowing up sequence of clastic rocks. Siltstones in its base are gradually replaced by sandstones toward its top. Initially, only sandstones were considered as oil-bearing, while siltstones were considered as water-bearing based on saturation calculation by means of Archie’s equation (Archie 1942) with the same values of cementation and saturation exponent for the whole formation. However, follow-up well tests detected considerable oil inflow also from the base of the reservoir composed of siltstones. Therefore, better rock typing was needed to improve the initial saturation distribution calculation. An applied approach that was based on integrated analysis of rock microstructural characteristics and derived from the NMR and CT techniques and conventional properties used for reserves calculation appeared to be an effective tool for rock typing polymineral clastic reservoirs. Measuring porous network characteristics and conventional properties in the same core plug enables a confident correlation between all measured parameters. Consequently, rock typing of samples based on flow units’ microstructural characteristics derived from NMR and CT scanning has shown a very good consistency with each other. As a result, four rock types were distinguished within a formation, which were previously interpreted as a single rock type. The detailed rock typing of the reservoir allowed more accurate reserves calculation and involvement of additional intervals into the production. Besides porous media characterization, CT scanning proved to be an effective tool for detecting minerals, such as pyrite and carbonates, characterizing depositional environments. Increasing content of pyrite in siltstones, detected by CT scanning and X-ray fluorescence spectroscopy, indicates deeper and less oxic conditions, while the presence of carbonate shell debris indicates shallower, more oxic depositional settings. The NMR test results show that the NMR signal distribution is affected by both pore size distribution and mineralogical composition. An increase of pyrite content caused shifting of the T2 distribution to the lower values, while carbonate inclusions caused shifting of the T2 distribution to higher values relative to the other samples not affected by these mineral inclusions. Because NMR distribution is affected by multiple factors, applying Т2cutoff values alone for rock typing can lead to ambiguous interpretation. Applying CT scanning next to NMR data increases the reliability of rock typing. The proposed laboratory workflow, including a combination of nonhazardous and nondestructive tests, allowed reliable differentiation of the rock samples based on multiple parameters that were interpreted in relationship with each other. Because the designed laboratory test workflow enabled both justified separation of the samples by rock type and determination of parameters used for reserves calculation, it can be recommended for further application in polymineral clastic reservoirs. Because the proposed techniques are nondestructive, the same samples can be applied for multiple tests including special core analysis (or SCAL).


2021 ◽  
Vol 25 (3) ◽  
pp. 275-284
Author(s):  
Helmer Fernando Alarcón Olave ◽  
Edwar Hernando Herrera Otero

The Cesar-Ranchería basin has all the necessary elements for the generation, expulsion, and migration of hydrocarbons and considerable potential for coal bed methane (CBM) in Colombia. Previous studies in the Cesar basin focused on understanding the tectonic evolution, stratigraphy, hydrocarbon generation potential, and evaluation of reservoir potential in Cretaceous calcareous units and quartzose sandstones from the Paleocene Barco Formation. These studies had confirmed the existence of an effective petroleum system, with several episodes of oil expulsion and re-emigration in the Miocene period, turning the Cenozoic clastic succession (Barco, Los Cuervos, La Loma, and Cuesta formations) into an element of significant exploratory interest to clarify the potentiality of the basin in terms of hydrocarbon accumulation. The petrophysical parameters of Cenozoic units (shale volume, porosity, water, and oil saturation) were determined by integrating wells log and core samples analyses from three stratigraphic wells. The integration of these results synthesizes the petrophysical behavior of the units. It defines intervals with clay volumes of less than 30%, effective porosity around 20%, which means favorable characteristics as reservoir rocks that need to be considered in future exploratory projects.


2021 ◽  
Author(s):  
Vasif Kurbanov ◽  
Andrey Chvertkov ◽  
Ekaterina Panarina

Abstract The development of clastic reservoirs can be complicated by heterogeneity both along the section and along the strike of the formations, therefore, an extended set of studies is especially necessary at such objects, both during drilling and during production. To determine the structure of the void, seismic surveys are usually used, which are limited in scale. An additional tool for defining geological boundaries is well. Well testing carried out in a timely manner, together with the analysis of production data, attribute analysis and geophysical survey data in the open hole, made it possible to identify the heterogeneity of the drainage zone in the early stages of operation and adjust the volume of geological reserves, therefore, to predict production with the highest degree of reliability.


2021 ◽  
Author(s):  
Alister Albert Suggust ◽  
Aizuddin Khalid ◽  
Mohammad Zulfiqar Usop ◽  
M Idraki M Khalil

Abstract The Balingian province is located offshore Sarawak, comprising of at least 7 oil fields with its regional geology consisting of a combination of deltaic & shoreface system. Though consisting of clastic reservoirs, the fields are highly sophisticated in terms of reservoir compartmentalization, hence uncertainties in fluid contacts, differing depletion strategies and varying production performance per well. As the regional production has gone into brownfield stage, the challenge is to determine the most suitable secondary recovery method to prolong field life. The subsurface & feasibility studies conducted produced mixed results between application of water & gas injection, giving recovery factors between 30 to 40%, and implementation so much depending on source of water & gas and cost benefit analyses. The application of IOR across Balingian province are executed in pilot mode across all fields. While the pilots are still continuing, this paper is to share the methodology, recovery factors and process of the regional study and some results from the ongoing surveillance post-execution, and the wayforward.


Sign in / Sign up

Export Citation Format

Share Document