Application of a Modern Electrical Borehole Imager and a New Image Interpretation Technique to Evaluate the Porosity and Permeability in Carbonate Reservoirs

2010 ◽  
pp. 1-13
Keyword(s):  
Image Interpretation ◽  
Carbonate Reservoirs ◽  
Porosity And Permeability

Using Logging and Seismic Data to Identify Boundaries Between Different OWC Units in a Deepwater Carbonate Reservoirs

2021 ◽  
Author(s):  
Kangxu Ren ◽  
Junfeng Zhao ◽  
Jian Zhao ◽  
Xilong Sun
Keyword(s):  
Seismic Data ◽  
Carbonate Rocks ◽  
Carbonate Reservoir ◽  
Carbonate Reservoirs ◽  
Sedimentary Process ◽  
Core Samples ◽  
Tight Carbonate ◽  
Porosity And Permeability ◽  
Seismic Sections ◽  
Parameters Inversion

Abstract At least three very different oil-water contacts (OWC) encountered in the deepwater, huge anticline, pre-salt carbonate reservoirs of X oilfield, Santos Basin, Brazil. The boundaries identification between different OWC units was very important to help calculating the reserves in place, which was the core factor for the development campaign. Based on analysis of wells pressure interference testing data, and interpretation of tight intervals in boreholes, predicating the pre-salt distribution of igneous rocks, intrusion baked aureoles, the silicification and the high GR carbonate rocks, the viewpoint of boundaries developed between different OWC sub-units in the lower parts of this complex carbonate reservoirs had been better understood. Core samples, logging curves, including conventional logging and other special types such as NMR, UBI and ECS, as well as the multi-parameters inversion seismic data, were adopted to confirm the tight intervals in boreholes and to predicate the possible divided boundaries between wells. In the X oilfield, hundreds of meters pre-salt carbonate reservoir had been confirmed to be laterally connected, i.e., the connected intervals including almost the whole Barra Velha Formation and/or the main parts of the Itapema Formation. However, in the middle and/or the lower sections of pre-salt target layers, the situation changed because there developed many complicated tight bodies, which were formed by intrusive diabase dykes and/or sills and the tight carbonate rocks. Many pre-salt inner-layers diabases in X oilfield had very low porosity and permeability. The tight carbonate rocks mostly developed either during early sedimentary process or by latter intrusion metamorphism and/or silicification. Tight bodies were firstly identified in drilled wells with the help of core samples and logging curves. Then, the continuous boundary were discerned on inversion seismic sections marked by wells. This paper showed the idea of coupling the different OWC units in a deepwater pre-salt carbonate play with complicated tight bodies. With the marking of wells, spatial distributions of tight layers were successfully discerned and predicated on inversion seismic sections.

scholarly journals Key controls on the hydraulic properties of fault rocks in carbonates

2020 ◽  
pp. petgeo2020-034
Author(s):  
E. A. H. Michie ◽  
A. P. Cooke ◽  
I. Kaminskaite ◽  
J. C. Stead ◽  
G. E. Plenderleith ◽  
...  
Keyword(s):  
Carbonate Reservoirs ◽  
Rock Properties ◽  
Burial Depth ◽  
Extrinsic Factors ◽  
Fault Rock ◽  
Fault Rocks ◽  
Content Type ◽  
Intrinsic Factors ◽  
Hydraulic Behaviour ◽  
Porosity And Permeability

A significant knowledge gap exists when analysing and predicting the hydraulic behaviour of faults within carbonate reservoirs. To improve this, a large database of carbonate fault rock properties has been collected from 42 exposed faults, from seven countries. Faults analysed cut a range of lithofacies, tectonic histories, burial depths and displacements. Porosity and permeability measurements from c. 400 samples have been made, with the goal of identifying key controls on the flow properties of fault rocks in carbonates. Intrinsic and extrinsic factors have been examined, such as host lithofacies, juxtaposition, host porosity and permeability, tectonic regime, displacement, and maximum burial depth, as well as the depth at the time of faulting. The results indicate which factors may have had the most significant influence on fault rock permeability, improving our ability to predict the sealing or baffle behaviour of faults in carbonate reservoirs. Intrinsic factors, such as host porosity, permeability and texture, appear to play the most important role in fault rock development. Extrinsic factors, such as displacement and kinematics, have shown lesser or, in some instances, a negligible control on fault rock development. This conclusion is, however, subject to two research limitations: lack of sufficient data from similar lithofacies at different displacements, and a low number of samples from thrust regimes.Thematic collection: This article is part of the Fault and top seals collection available at: https://www.lyellcollection.org/cc/fault-and-top-seals-2019

Trapped-Gas Saturations in Carbonate Formations

1975 ◽  
Vol 15 (02) ◽  
pp. 149-160 ◽  
Author(s):  
Dare K. Keelan ◽  
Virgil J. Pugh
Keyword(s):  
Rock Type ◽  
Pore Space ◽  
Gas Storage ◽  
Carbonate Reservoirs ◽  
Type I ◽  
Type Ii ◽  
Gas Saturation ◽  
Porosity And Permeability ◽  
Trapped Gas ◽  
Carbonate Formations

Abstract Trapped-gas saturations existing after gas displacement by wetting-phase imbibition are presented for selected carbonate reservoirs. presented for selected carbonate reservoirs. Formations representing various rock types were investigated, and samples covering the porosity and permeability range within each field were tested. Cores from Smackover reservoirs located within four states were included to examine differences in trapped gas that might occur within a carbonate deposited over a large geographical area. The trapped gas varied with initial gas in place and with rock type. With gas in place of 80 percent of pore space, trapped gas values ranged from a low of 23 percent of pore space in Type II chalk to a maximum of 69 percent in Type I limestone evaluated. Correlation of trapped-gas saturation values was attempted using several approaches, but none was entirely satisfactory. Essentially no relationship with permeability was found within most reservoirs or between different reservoirs. Within a given field, trapped gas at a common initial gas saturation typically increased as porosity decreased. A general interfield correlation with porosity was noted, but certain anomalous data were observed. Knowledge of rock type was necessary to explain these variations in trapped-gas saturations. It was concluded that the complexity of carbonates necessitates determination of trapped gas on the specific reservoir to be evaluated. Introduction Gas reservoirs with a naturally occurring underlying aquifer and aquifer gas storage projects both offer possibilities for large volumes of gas to be trapped and unrecovered. This trapping results from gas-water capillary forces that become active as production occurs and as water encroaches into pore space that previously contained interstitial pore space that previously contained interstitial water and gas. The magnitude of the trapped gas has been reported by others for sandstones, but essentially no information is available in the technical literature for carbonates. A series of carbonate reservoirs was studied to define the magnitude of trapped gas that existed for the range of porosity and permeability found within each reservoir. Trapped-gas saturation values were developed on each core for an initial gas saturation corresponding to irreducible water. Two cores from each reservoir were tested to yield additional trapped saturations for initial gas values of 20 and 50 percent of pore space. These additional data assist in defining trapped gas within a gas-water transition zone or within a gas storage aquifer where considerable variation in gas saturation may exist. Carbonate formations studied were selected to cover a range in pore geometry. Porosity and permeability were not sufficient to classify the permeability were not sufficient to classify the samples or correlate the data. Archie arrived at a classification of carbonate rocks based on the texture of the rock matrix and the nature of the visible pore structure. Table 1 is a summary of the classification, with slight modifications by Jodry. TABLE 1 - ARCHIE ROCK CLASSIFICATION Texture of Appearance of Appearance Under Matrix Hand Sample 10-Power Microscope Type I Crystalline, hard, dense Compact with smooth face on No visible pore space Crystalline breaking. Resinous between crystals Type II Small crystals are less Chalky Dull, earthy, or chalky than 0.05 mm and are earthy with pore space barely visible. Type III Space indicated Granular or Sandy or sugary between crystals or Sucrosic (sucrose) grains. Oolites are in granular class. Matrix Grain Size Symbol Large (coarse) >0.5 mm 1 Medium 0.25 to 0.5 mm m Fine 0.125 to 0.25 mm f Very fine 0.0625 to 0.125 mm vf Extremely fine < 0.0625 mm xf Pore-Size Classification Pore-Size Classification Visible to Visible Diameter Class Naked Eye 10x Magnification (ml) A No No <0.01 B No Yes 0.01 to 0.1 C Yes Yes 0.1 to 1.0 D Yes Yes >1.0 SPEJ P. 149

scholarly journals Classification of Void Space Types in Fractured-Vuggy Carbonate Reservoir Using Geophysical Logging: A Case Study on the Sinian Dengying Formation of the Sichuan Basin, Southwest China

Energies ◽  
2021 ◽  
Vol 14 (16) ◽  
pp. 5087
Author(s):  
Kunyu Wang ◽  
Juan Teng ◽  
Hucheng Deng ◽  
Meiyan Fu ◽  
Hongjiang Lu
Keyword(s):  
Sichuan Basin ◽  
Southwest China ◽  
Carbonate Reservoir ◽  
Carbonate Reservoirs ◽  
Void Space ◽  
Identification Method ◽  
Geophysical Logging ◽  
Dengying Formation ◽  
Porosity And Permeability ◽  
Core Description

The fractured-vuggy carbonate reservoirs display strong heterogeneity and need to be classified into different types for specific characterization. In this study, a total of 134 cores from six drilled wells and six outcrops of the Deng #2 and Deng #4 members of the Dengying Formation (Sichuan Basin, Southwest China) were selected to investigate the petrographic characteristics of void spaces in the fractured-vuggy carbonate reservoirs. Four void space types (VSTs) were observed, namely the solution-filling type (SFT), cement-reducing type (CRT), solution-filling breccia type (SFBT) and solution-enlarging fractures and vugs type (SEFVT). The CRT void spaces presented the largest porosity and permeability, followed by the SEFVT, SFBT and SFT. The VSTs presented various logging responses and values, and based on these, an identification method of VSTs using Bayes discriminant analysis (BDA) was proposed. Two test wells were employed for the validation of the identification method, and the results show that there is good agreement between the identification results and core description. The vertical distribution of VSTs indicates that the SFT and SEFVT are well distributed in both the Deng #2 and Deng #4 members. The CRT is mainly found in the Deng #2 member, and the SFBT occurs in the top and middle of the Deng #4 member.

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