scholarly journals Pore Structure Characteristics and Permeability Prediction Model in a Cretaceous Carbonate Reservoir, North Persian Gulf Basin

Geofluids ◽  
2021 ◽  
Vol 2021 ◽  
pp. 1-19
Author(s):  
Hao Lu ◽  
Hongming Tang ◽  
Meng Wang ◽  
Xin Li ◽  
Liehui Zhang ◽  
...  
Keyword(s):  
Pore Structure ◽  
Oil Recovery ◽  
Prediction Models ◽  
Carbonate Reservoir ◽  
Good Prediction ◽  
Type I ◽  
Permeability Prediction ◽  
Rock Types ◽  
Fluid Saturation ◽  
Pore Types

Due to the diversity of pore types, it is challenging to characterize the Middle East’s Cretaceous carbonate reservoir or accurately predict its petrophysical properties. In this paper, pore structure in the reservoir is first classified using a comprehensive method. Then, based on the identified pore structure types, a new permeability model with high prediction precision is established. The reservoir is dominated by 6 pore types, such as intergrain pores and moldic pores, and 6 rock types. Grainstone, algal packstone, algal wackestone, and foraminifera wackestone are porous rock types, and echinoderm wackestone and mudstone are nonporous rock types. The types of pore structure in the study area can be divided into four types. Type I has midhigh porosity and medium-high permeability due to its large throat, while type II has a fine throat type with midhigh porosity and midpermeability. Due to their isolated pores, the permeability is low in types III and IV, and out of these two, type III has better storage capacity. Movable fluid saturation calculated by the spectral coefficient method and r apex can characterize the boundary between the connected pores and unconnected pores very well in the research area. It is not accurate enough to simply classify the pore structure by permeability and porosity. The combination of porosity, permeability, r apex , flow zone indicator, and the reservoir quality index can effectively distinguish and classify pore structure types in noncoring wells. The characteristics of each pore structure type are consistent with those of the fractal dimension, which thereby proves the effectiveness of the pore structure classification. New permeability prediction models are proposed for different pore structure types, and good prediction results have been obtained. This study is of great significance for enhancing oil recovery.

scholarly journals Fluid Saturation Predictions in a “Transition Zone” Carbonate Reservoir, Abu Dhabi

GeoArabia ◽  
1996 ◽  
Vol 1 (4) ◽  
pp. 551-566
Author(s):  
Anthony Kirkham ◽  
Mohamed Bin Juma ◽  
Tilden A.M. McKean ◽  
Anthony F. Palmer ◽  
Michael J. Smith ◽  
...  
Keyword(s):  
Transition Zone ◽  
Free Water ◽  
Analysis Data ◽  
Carbonate Reservoir ◽  
Rock Types ◽  
Fluid Saturation ◽  
Porosity And Permeability ◽  
Capillary Pressures ◽  
Seismic Amplitudes ◽  
Low Amplitude

ABSTRACT The field is a low amplitude structure with a chalky, Lower Cretaceous, Thamama reservoir characterised by a large hydrocarbon transition zone. Porosity generally decreases with depth within the trap although porosity versus depth trends are skewed by tilting. Porosity and permeability mapping was therefore achieved using templates based on seismic amplitudes. Special core analysis data were used to construct algorithms of Leverett J functions versus saturation for a variety of rock types mapped throughout the 3-D geological model of the field. The templated poroperms were then combined with capillary pressures to predict fluid saturations from these algorithms. The modelling of fluid distributions was therefore dependent upon heterogeneities imposed by the rock fabrics. Calibrating the model-predicted saturations against log-derived saturations at the wells involved regression techniques which were complicated by: notional structural tilting of the free water level, imbibition, hysteresis and permeability averaging procedures. Filtered “stick displays” proved useful in assessing the quality of the calibrations and were invaluable tools for highlighting and investigating data anomalies.

Improving Porosity–Velocity Relationships Using Carbonate Pore Types

2015 ◽  
Vol 23 (04) ◽  
pp. 1540006 ◽  
Author(s):  
Tingting Zhang ◽  
Yuefeng Sun ◽  
Qifeng Dou ◽  
Hanrong Zhang ◽  
Tonglou Guo ◽  
...  
Keyword(s):  
Pore Structure ◽  
Acoustic Impedance ◽  
Carbonate Rocks ◽  
Seismic Inversion ◽  
Carbonate Reservoir ◽  
Reservoir Rocks ◽  
Fluid Content ◽  
Fracture Fluid ◽  
Poroelastic Model ◽  
Pore Types

Acoustic impedance in carbonates is influenced by factors such as porosity, pore structure/fracture, fluid content, and lithology. Occurrence of moldic and vuggy pores, fractures and other pore structures due to diagenesis in carbonate rocks can greatly complicate the relationships between impedance and porosity. Using a frame flexibility factor ([Formula: see text]) derived from a poroelastic model to characterize pore structure in reservoir rocks, we find that its product with porosity can result in a much better correlation with sonic velocity ([Formula: see text] = [Formula: see text]) and acoustic impedance ([Formula: see text] = [Formula: see text], where A, B, C and D is 6.60, 0.03, 18.3 and 0.09, respectively for the deep low-porosity carbonate reservoir studied in this paper. These new relationships can also be useful in improving seismic inversion of ultra-deep hydrocarbon reservoirs in other similar environments.

scholarly journals Integrated rock typing and pore facies analyses in a heterogeneous carbonate for saturation height modelling, a case study from Fahliyan Formation, the Persian Gulf

2021 ◽  
Vol 11 (4) ◽  
pp. 1577-1595
Author(s):  
Rasoul Ranjbar-Karami ◽  
Parisa Tavoosi Iraj ◽  
Hamzeh Mehrabi
Keyword(s):  
Capillary Pressure ◽  
Water Saturation ◽  
High Energy ◽  
Carbonate Reservoir ◽  
Reservoir Rock ◽  
Initial Water ◽  
Rock Types ◽  
Rock Typing ◽  
Pore Types ◽  
Fitting Parameters

AbstractKnowledge of initial fluids saturation has great importance in hydrocarbon reservoir analysis and modelling. Distribution of initial water saturation (Swi) in 3D models dictates the original oil in place (STOIIP), which consequently influences reserve estimation and dynamic modelling. Calculation of initial water saturation in heterogeneous carbonate reservoirs always is a challenging task, because these reservoirs have complex depositional and diagenetic history with a complex pore network. This paper aims to model the initial water saturation in a pore facies framework, in a heterogeneous carbonate reservoir. Petrographic studies were accomplished to define depositional facies, diagenetic features and pore types. Accordingly, isolated pores are dominant in the upper parts, while the lower intervals contain more interconnected interparticle pore types. Generally, in the upper and middle parts of the reservoir, diagenetic alterations such as cementation and compaction decreased the primary reservoir potential. However, in the lower interval, which mainly includes high-energy shoal facies, high reservoir quality was formed by primary interparticle pores and secondary dissolution moulds and vugs. Using huge number of primary drainage mercury injection capillary pressure tests, we evaluate the ability of FZI, r35Winland, r35Pittman, FZI* and Lucia’s petrophysical classes in definition of rock types. Results show that recently introduced rock typing method is an efficient way to classify samples into petrophysical rock types with same pore characteristics. Moreover, as in this study MICP data were available from every one meter of reservoir interval, results show that using FZI* method much more representative sample can be selected for SCAL laboratory tests, in case of limitation in number of SCAL tests samples. Integration of petrographic analyses with routine (RCAL) and special (SCAL) core data resulted in recognition of four pore facies in the studied reservoir. Finally, in order to model initial water saturation, capillary pressure data were averaged in each pore facies which was defined by FZI* method and using a nonlinear curve fitting approach, fitting parameters (M and C) were extracted. Finally, relationship between fitting parameters and porosity in core samples was used to model initial water saturation in wells and between wells. As permeability prediction and reservoir rock typing are challenging tasks, findings of this study help to model initial water saturation using log-derived porosity.

scholarly journals Pore Structure Characteristics of Tight Carbonate Reservoir in Qingxi Sag, Jiuquan Basin

Lithosphere ◽  
2021 ◽  
Vol 2021 (Special 1) ◽  
Author(s):  
Xiangye Kong ◽  
Jianhui Zeng ◽  
Xianfeng Tan ◽  
Xianglu Gao ◽  
Yu Peng ◽  
...  
Keyword(s):  
Pore Structure ◽  
Tube Bundle ◽  
Pore Space ◽  
Carbonate Reservoir ◽  
Reservoir Rock ◽  
Tight Oil ◽  
Type I ◽  
Structure Characteristics ◽  
Small Pore ◽  
Tight Carbonate

Abstract The Xiagou Formation is the main tight oil reservoir in Qingxi Sag of Jiuquan Basin. Given the poor physical properties and other factors restricting tight oil exploitation and production in this area, studies should focus on microscopic pore structure characteristics. In this study, a nano-CT scanner, a SEM, and an NMR were used to study the pore structure characteristics of a tight carbonate reservoir in Qingxi Sag, Jiuquan Basin. The Xiagou Formation reservoir mainly consists of gray argillaceous dolomite and dolomitic mudstone. The pore categories are mainly elliptic, irregular, intergranular, and intragranular and mostly filled with clay and carbonate cement. Pore space is small, the intergranular or organic pores are mostly separated, and pore-throat is weakly connected. The throats mostly develop with lamellar and tube bundle-like characteristics and with poor seepage ability. The pore-throats mostly span from nanometer to micrometer sizes, and pore diameters are mainly concentrated in the range of 0.01–0.1 and 1–10 μm. It is a unimodal pattern mainly composed of micropores, or a bimodal regular allocation dominated by micropores supplemented by macropores. The relationship between micropore (<0.1 μm) and macropore (>1 μm) content allocation and mean pore diameter strongly controls the permeability of reservoir rocks. When macropore content reaches more than 85%, or when pore content totals less than 3%, the permeability of a reservoir remarkably increases. At a higher ratio of the average finest throat sectional area and throat-pore of reservoir rock, the throat radius lies closer to the connecting pore radius, pore and throat connectivity improves, and reservoir seepage ability becomes stronger. Based on reservoir capacity and seepage ability, pore structures of the tight carbonate reservoirs in study area are classified into type I (small-pore–thin-throat), type II (thin-pore–thin-throat), and type III (microporous-microthroat) with rock permeability>0.1 mD, 0.05–0.1 mD, and <0.05 mD, respectively. The type I pore structure reservoir should be regarded as an indicator of tight oil “sweet spots” reservoir in the study area.

Comparison of Oil Recovery and Carbonate Rock’s Properties Alterations by CO2 Miscible Flooding

2018 ◽  
Author(s):  
Jinju Han ◽  
Youngjin Seo ◽  
Juhyun Kim ◽  
Sunlee Han ◽  
Youngsoo Lee
Keyword(s):  
Pore Structure ◽  
Oil Recovery ◽  
Carbonate Rock ◽  
Flow Path ◽  
Carbonate Reservoir ◽  
Rock Properties ◽  
Co2 Flooding ◽  
Miscible Flooding ◽  
The Impact ◽  
Indiana Limestone

This present study indicates experimental investigation about the impact of CO2 flooding on oil recovery and rock’s properties alteration in carbonate reservoir under the miscible condition. In order to compare the effect to initial pore characteristic, two type of carbonate rock was used; an Edward white represents homogeneous mainly consisted micropore, whereas an Indiana limestone represented heterogeneous mainly consisted macropore in this study. Under the miscible condition (9.65 MPa and 40°C), five pore volume of CO2 were injected into oil-wet carbonate rock, which was fully saturated with oil and connate water. After CO2 flooding, several analyses for each sample conducted to investigate oil recovery and rock properties change in porosity, permeability, and pore structure by chemical and physical reaction between CO2, water, and carbonate mineral before and after CO2 flooding by using core analysis, MICP, SEM, ICP, and X-ray CT techniques. From the results of oil recovery, it was more effective and larger in Edward white than in Indiana limestone. Because homogeneous characteristic with a large ratio of low permeable micropore in Edward white contributed to occur long reaction time between oil and CO2 for enough miscibility as well as to displace stably oil by CO2. Conversely, heterogeneous pore structure mainly consisted of high permeable conduit (macropore) in Indiana limestone has brought ineffective and low oil production. From the analysis of rock’s properties alteration, we found that, for the homogeneous sample, dissolution dominantly changed pore structure and became better flow path by improving permeability and reducing tortuosity. While plugging by precipitation of mineral particles was not critically affected rock’ properties, despite the sample mainly consisted small pores. In the case of the heterogeneous sample, both dissolution and precipitation critically affected change of rock’s properties and pore structure. In particular, superior precipitation in complex pore network seriously damaged flow path and change of rock’s properties. The largest porosity change markedly appeared in inlet section because of exposing rock surface from fresh CO2 during a long time. In conclusion, it shows that CO2 miscible flooding in carbonate reservoirs significantly affected to alteration of rock’s properties such as porosity, permeability, tortuosity, and pore connectivity, in particular in heterogeneous system compared with in homogeneous system. These experimental results can be useful to characterize carbonate rock as well as to study rock properties alteration on CO2 EOR and CCS processes.

Gas/Oil Relative Permeability Normalization: Effects of Permeability, Wettability, and Interfacial Tension

2016 ◽  
Vol 19 (04) ◽  
pp. 673-682 ◽  
Author(s):  
Amir Jahanbakhsh ◽  
Hamidreza Shahverdi ◽  
Mehran Sohrabi
Keyword(s):  
Interfacial Tension ◽  
Oil Recovery ◽  
Absolute Permeability ◽  
Fluid Distribution ◽  
Gas Oil ◽  
Relative Permeabilities ◽  
Two Phase ◽  
Rock Types ◽  
Fluid Saturation ◽  
Oil Flow

Summary Relative permeabilities (kr) are crucial flow functions governing the fluid distribution within and production from petroleum reservoirs under various oil-recovery methods. To obtain these important reservoir parameters, conventionally, it is required to take rock samples from the reservoir and perform appropriate laboratory measurements. Although kr is expressed as a function of fluid saturation, it is now well-known that kr values are affected by pore structure and distribution, absolute permeability, wettability, interfacial tension (IFT), and saturation history. These rock/fluid properties often change from one region of the reservoir to another, but it would be impossible to perform kr measurements for all regions of a reservoir. Generally, performing experiments on a core with higher permeability is faster and easier than a low-permeability rock. Therefore, assuming all other parameters such as wettability, IFT, and displacement direction are the same for two rocks with different permeabilities, the question becomes how do we estimate the kr of a rock with lower permeability from available (measured) kr of a higher-permeability rock? How do we account for wettability and IFT differences? A normalization technique has been proposed to remove the effect of irreducible water and trapped saturations, which would be different under different conditions. The relative permeabilities can then be denormalized and assigned to different regions (rock types) of the reservoir on the basis of their own irreducible water and trapped saturations. The objective of this study is to introduce a methodology to predict the gas/oil kr for new rock/fluid conditions (such as permeability, wettability, and IFT) by use of existing gas/oil kr data measured at different conditions. By use of measured data from coreflood experiments, we show that by applying an appropriate normalization technique one can adequately predict kr of rocks with different permeability and wettability conditions in two-phase gas/oil flow. However, the results show that the effect of IFT change cannot be captured by normalization techniques. To improve the methodology, a new hypothesis is introduced and proposed here on the basis of dynamic trap saturation. Finally, by use of our experimental data, we evaluate the validity of the Coats (1980) IFT scaling method. We demonstrate the shortcomings of the method and offer an improvement to its prediction.

scholarly journals Petrophysical Properties of an Iraqi Carbonate Reservoir Using Well Log Evaluation

2020 ◽  
Vol 21 (1) ◽  
pp. 53-59
Author(s):  
Sarah S. Zughar ◽  
Ahmad A. Ramadhan ◽  
Ahmed K. Jaber
Keyword(s):  
Water Saturation ◽  
Carbonate Reservoir ◽  
Petrophysical Properties ◽  
Indicator Method ◽  
Rock Types ◽  
Fluid Saturation ◽  
Unit Thickness ◽  
Average Formation ◽  
Porous Zone ◽  
Mud Filtration

This research was aimed to determine the petrophysical properties (porosity, permeability and fluid saturation) of a reservoir. Petrophysical properties of the Shuiaba Formation at Y field are determined from the interpretation of open hole log data of six wells. Depending on these properties, it is possible to divide the Shuiaba Formation which has thickness of a proximately 180-195m, into three lithological units: A is upper unit (thickness about 8 to 15 m) involving of moderately dolomitized limestones; B is a middle unit (thickness about 52 to 56 m) which is composed of dolomitic limestone, and C is lower unit ( >110 m thick) which consists of shale-rich and dolomitic limestones. The results showed that the average formation water resistivity for the formation (Rw = 0.021), the average resistivity of the mud filtration (Rmf = 0.57), and the Archie parameters determined by the picket plot method, where m value equal to 1.94, n value equal to 2 and a value equal to 1. Porosity values and water saturation Sw were calculated along with the depth of the composition using IP V3.5 software. The interpretation of the computer process (CPI) showed that the better porous zone holds the highest amount of hydrocarbons in the second zone. From the flow zone indicator method, there are four rock types in the studied reservoir.

Correlation of Pore Structure and Permeability by SEM-Image Analysis

1990 ◽  
Vol 48 (1) ◽  
pp. 428-429
Author(s):  
C. A. Callender ◽  
Wm. C. Dawson ◽  
J. J. Funk
Keyword(s):  
Image Analysis ◽  
Pore Structure ◽  
Imaging System ◽  
Pore Space ◽  
Simulation Models ◽  
Image Analyzer ◽  
Imaging Data ◽  
Sem Images ◽  
Thin Sections ◽  
Rock Types

The geometric structure of pore space in some carbonate rocks can be correlated with petrophysical measurements by quantitatively analyzing binaries generated from SEM images. Reservoirs with similar porosities can have markedly different permeabilities. Image analysis identifies which characteristics of a rock are responsible for the permeability differences. Imaging data can explain unusual fluid flow patterns which, in turn, can improve production simulation models.Analytical SchemeOur sample suite consists of 30 Middle East carbonates having porosities ranging from 21 to 28% and permeabilities from 92 to 2153 md. Engineering tests reveal the lack of a consistent (predictable) relationship between porosity and permeability (Fig. 1). Finely polished thin sections were studied petrographically to determine rock texture. The studied thin sections represent four petrographically distinct carbonate rock types ranging from compacted, poorly-sorted, dolomitized, intraclastic grainstones to well-sorted, foraminiferal,ooid, peloidal grainstones. The samples were analyzed for pore structure by a Tracor Northern 5500 IPP 5B/80 image analyzer and a 80386 microprocessor-based imaging system. Between 30 and 50 SEM-generated backscattered electron images (frames) were collected per thin section. Binaries were created from the gray level that represents the pore space. Calculated values were averaged and the data analyzed to determine which geological pore structure characteristics actually affect permeability.

Sign in / Sign up

Export Citation Format

Share Document