Evaluation Of Carbonate Reservoirs Research Articles

Classification of rock types of porous limestone reservoirs: case study of the A oilfield

Rock types with similar lithological components and pore structures form the basic units of porous limestone reservoirs; this influences the reservoir evaluation efficiency and water injection development. As the main oil and gas pay zone in central Iraq, the Cretaceous Khasib Formation reservoirs are influenced by deposition, dissolution, and cementation. There is strong vertical heterogeneity in the most important zone of the Kh2 layer, with diverse rock types and complex pore structures. Based on core observation and casting thin-section identification, the Kh2 layer in the study area was divided into eight lithofacies types as argillaceous bioclastic wackestone, planktic foraminiferium wackestone, lamellar bioclastic wackestone, intraclastic–bioclastic packstone, patchy green algae packstone, green algae and pelletoid packstone, benthic foraminiferium–bioclastic packstone, and intraclastic grainstone. Along with the reservoir void space types of the lithofacies, capillary pressure curves are used to quantitatively analyze the throat and pore features of the different lithofacies. From the porosity–permeability cross-plot characteristics and distribution of pore types, 14 petrophysical facies are obtained. Finally, based on the differences between the lithofacies and petrophysical facies, the Kh2 member is divided into 13 rock types with different geological origins and petrophysical characteristics. Among these, the rock type RT1-8-14 has the best and rock type RT1-1-1 has the worst physical properties among the reservoir rock types. This study provides an optimization method for carbonate reservoir evaluation and is expected to be beneficial for efficient development of similar carbonate reservoirs.

The importance of core for carbonate reservoir evaluation: a case study from the Barra Velha Formation, Santos Basin, Brazil

Abstract The lacustrine carbonates of the Barra Velha Formation are a prolific hydrocarbon reservoir in the Santos Basin, Brazil. In many fields, they comprise decimetre- to metre-scale cycles composed of laminated calcimudstones, spherulite and shrub-dominated facies. However, locally these cycles are replaced by decametre packages of re-worked shrub grainstone/rudstone/breccia and in situ shrub framestone with significant (>30°) depositional dips. The latter could be interpreted in several ways (e.g. fault-block highs, carbonate mounds), but the integration of seismic, borehole image log and whole-core datasets converge on a model of aggrading carbonate mounds which developed in or marginal to a lake setting. The core datasets in this study demonstrate a distinctive depositional fabric within the carbonate mounds. From a production geology standpoint, the crucial difference between mound- and cyclothem-dominated successions is their permeability architecture. Cyclothem-dominated intervals show prominent and laterally continuous, decimetre-scale vertical matrix permeability variations. Mound-dominated intervals lack fine-scale palaeo-horizontal layering and exhibit a greater prevalence of irregular, centimetre-scale conduits and higher vertical permeability. This difference can only be reliably characterized via the integration of whole-core samples with other datasets and has a significant quantified impact on sweep and production performance.

Tight carbonate reservoir evaluation case study based on neural network assisted fracture identification and analytic hierarchy process

Comprehensive evaluation of reservoirs is an important link in gas reservoir exploration and development. The evaluation of tight carbonate reservoirs often focuses on the characteristics of porosity and permeability, ignoring the important factor of fractures, also the quantitative evaluation of reservoirs is relatively few. It is difficult to identify fractures and evaluate the reservoir factors qualitatively and quantitatively. Herein, the sedimentary microfacies and microporosity of the tight carbonate reservoir of the Ma55 submember in the eastern Sulige area are comprehensively studied by casting thin section, rock physical property, and capillary pressure test data. The backpropagation (BP) neural network algorithm is used to identify and predict fractures. Finally, through the analytic hierarchy process, the above reservoir influencing factors are modeled and quantitatively analyzed for reservoir evaluation. The results show that the highest probability of fracture development in the central and northwest areas of the study area can reach 0.92. The accuracy of the BP neural network model in identifying cracks can reach 80%, which is reliable and effective compared with the conventional logging identification method. Reservoirs can be classified into four types according to their quality. The synthetic weights of porosity, permeability and fracture development probability are 0.2, 0.2 and 0.216 respectively, which are the three most important evaluation parameters. This study improves the accuracy of fracture identification and prediction of tight reservoirs in comprehensive reservoir evaluation, which provides guidance and scheme for more detailed exploration and development of tight carbonate reservoirs.

Study on Sustainable Development of Carbonate Reservoir Based on 3D Printing Technology

With its abundant reserves in the world, carbonate reservoir has become one of the main targets for future oil and gas development. Accelerating the research and development of carbonate reservoirs is thus significant to enhance the world’s energy supply capacity. However, there have been some problems in the evaluation of carbonate reservoirs for a long time, such as low description accuracy of fractured-vuggy bodies, diverse flow patterns, and difficult reservoir simulation and prediction. Compared with traditional manufacturing methods, 3D printing is an advanced manufacturing technology of rapid prototyping. It has the characteristics of short manufacturing cycle, not limited by the complexity of parts, material saving and energy saving, and thus has unparalleled advantages in reservoir rock analysis. In this paper, the carbonate core of Yingmaili region in Tarim Basin was taken as the research object, and the uniaxial compression mechanical properties of three small cores printed with different materials were designed and tested by using KINGS-600 3D photocuring printer and photosensitive resin materials. After that, UV-9400S white resin with the highest strength is selected as the printing material of the full diameter core model of the karst cave. Combined with the CT scanning of the formed samples, the control accuracy concerning the cave morphology of the 3D printed samples was tested which adequately proves that flow experiments can be carried out with 3D printed core samples. At last, the article also analyzes the shortcomings of 3D printing technology, and points out the direction for its large-scale application in the field of oil and gas exploitation. This study can especially provide a reference for the application of 3D printing technology in the field of carbonate reservoir development, and ultimately promote the sustainable supply of oil and gas resources.

The Contribution of Petroleum Charging Episodes to Different Strike-Slip Fault Zones in the Shunbei Area, the Tarim Basin, NW China

In recent years, newly discovered ultra-deep fault-karst reservoirs in the Shunbei area of the Tarim Basin have greatly increased the prospectivity of the basin and become a hotspot for further hydrocarbon exploration. In this study, the diagenetic sequences of the Lower-Middle Ordovician reservoir were established through observation of thin sections under transmitted light, reflected light, and cathode luminescence. The hydrocarbon charge history in the Shunbei area was reconstructed and associated with a series of diagenetic events using fluid inclusion microthermometric measurements combined with one-dimensional basin modeling. The results show that the Shunbei area has experienced three hydrocarbon charging episodes in total, in the late Caledonian, late Hercynian, and late Himalayan. Finally, the relationship between measured QF-535 factors and the API gravity of crude oil was used to quantify the level of contribution of each of the petroleum charging episodes to the No. 1, No. 5, and No. 7 fault zone reservoirs. The contribution of early hydrocarbon charging episodes gradually increases from west to east in the Shunbei area. This increase was driven by different tectonic events throughout geological history and the subsequent evolution of paleo-structural patterns. This study has a significant impact on marine carbonate reservoir evaluation in strike-slip fault zones in China.

Fractal Characteristics of Pore-Throats Structure and Quality Evaluation of Carbonate Reservoirs in Eastern Margin of Pre-Caspian Basin

The Carboniferous reservoir KT-II layer in the Eastern margin of the Pre-Caspian Basin was formed in the open platform sedimentary environment and marked by a complicated pore-throats structure. Understanding the main controls on the carbonate reservoir quality is of great significance for reservoir classification and a relevant production prediction. This study focuses on revealing reservoir pore-throats structure’s fractal characteristics by analyzing the mercury intrusion capillary pressure (MICP), with the integration of the pore-throats radius’ distribution data. The relationship between fractal dimensions and reservoir parameters such as physical properties, mercury median saturation pressure (Pc50) and the proportion of large-size (radius > 0.1 μm) pores demonstrate that the lower fractal dimension corresponds not only to core plug samples with higher permeability, but also to lower Pc50 and a higher proportion of large pore-throats. Three classes of carbonate reservoir with different qualities were defined according to their fractal dimensions, petrophysical properties and photomicrograph features, et al. Combined with flow profiles from Production Log Tool tests, the relationship between the carbonate reservoir type and production behavior was revealed, thus providing suggestions on the middle and late stage of the water flooding production adjustment strategy. This work provides a typical case study for the further comprehensive evaluation and classification of a carbonate reservoir and it is quite meaningful for production efficiency optimization.

Fundamental constraints of lithologically-controlled fault networks on gas migration and accumulation for fractured carbonates in the western Sichuan Basin, China

The structure of subsurface fault networks, which has a significant effect on hydrocarbon migration, is inherently difficult to recognize and map. 3D seismic surveys provide an opportunity to map the fault system within a carbonate reservoir of Xinchang in the western Sichuan Basin, China. We calculated attributes from the seismic reflection data that covers an area of 1330 km2, including variance, edge detection, dip-magnitude and dip azimuth. We focused on the Triassic Leikoupo Formation of dolostone, at ∼6 km depth, adjacent to the Longmen Shan thrusting range. The mapped attributes display (1) a primary network of faults in an orthogonal pattern in the anticline, striking East-West and North-South, and (2) a secondary, conjugate fault set in the fold limb, striking Northeast and Northwest with a length range of 1–10 km. The latter set of conjugate faults are confined to a 300 m-thick layer of dolostone, diminishing into underlaying unit of anhydrite. We envision that the conjugate fault networks and associated fractures enhance gas charging and reflect a model of self-sourced migration and accumulation in the Leikoupo Formation. These results are significant for sweet-spot evaluation of carbonate reservoirs in the Sichuan Basin, and provide insights for understanding the migration of subsurface fluids.

A NOVEL APPROACH BASED ON FEATURE FUSION FOR FRACTURE IDENTIFICATION USING WELL LOG DATA

Accurate identification of fractures is necessary and complex for carbonate reservoir exploration. Using conventional well logs and geological data, we identify various fracture identification methods based on depth point information and waveform processing. The results show that the method based on equivalent medium theory maintains high stability and accuracy in reflecting the secondary pores in cases of unfavorable borehole environments. Both the acoustic log and dual lateral difference fractal dimensions increase in line with the degree of fracture development. The high-frequency energy information shows significantly high values in the fractured zone on a suitable scale. Finally, the fractures are characterized by a novel approach based on feature fusion. The linear predictive relationship for fracture identification via proposed comprehensive factor scores (CFS) avoids the influence of the deviation of a few variables on the stability of the overall results. Our study offers a new framework for fracture identification in the exploration and evaluation of carbonate reservoirs.

A method to analyze fracture communication in carbonate reservoirs

Large amounts of oil and gas resources are stored in carbonate rocks, and fracturing is an important technology to exploit carbonate reservoirs, The communication between artificial fractures and natural fractures is very important for the fracturing effect of carbonate reservoirs, The effect evaluation after fracturing lacks quantitative description. Therefore, it is necessary to study the fracturing effect evaluation of carbonate reservoirs. This paper analyzes the pressure curve obtained in true triaxial fracturing experiment. The communication with natural fracture and vugs in the process of fracture propagation is explored. Finally, the pressure curve characteristics of artificial fracture communicating with natural fracture cavity under different modes are obtained, and the communication between artificial fracture and natural fracture is identified.

Geophysical pore type inversion in carbonate reservoir: Integration of cores, well logs, and seismic data (Yadana field, offshore Myanmar)

Detection of pore types and diagenetic features from seismic data is a major challenge for the evaluation of carbonate reservoirs in the subsurface. Based on a detailed petrographical and petrophysical analysis of carbonate rock using optical and scanning electron microscopy, mercury-injection measurements, digital image analysis, and well logs, we have determined the potential of the geophysical pore type ([Formula: see text]) inversion — a rock physics inversion scheme based on the differential effective medium theory—to quantitatively and qualitatively characterize the pore type distribution from acoustic data in the Yadana carbonate gas field (Early Miocene, offshore Myanmar). The geophysical pore type ([Formula: see text]) is revealed to be an upscalable parameter, whose depositional/diagenetic interpretation may be performed at well log and at seismic scales. We apply the inversion method on a 3D seismic data to map the reservoir-scale distribution and highlight the occurrence of laterally extended (100–1000 m) subseismic- to seismic-scale (thickness [Formula: see text]) geologic bodies. From this approach, two main reservoir geobodies are discriminated and interpreted in terms of depositional and diagenetic fabrics: (1) highly microporous, decameter-scale reservoir units (approximately 80% of the reservoir), mainly consisting of foraminiferal, red algae floatstone to rudstone with vuggy moldic porosity and characterized by moderate to high [Formula: see text] (0.11–0.20) and (2) thin, stratiform, cemented scleractinian floatstone/brecciated units (5–10 m; approximately 20% of the reservoir) with low microporosity and macroporosity and exhibiting low [Formula: see text] values ([Formula: see text]).

Seismic expression of miocene carbonate platform and reservoir characterization through geophysical approach: application in central Luconia, offshore Malaysia

A substantial proportion of proven oil and gas reserves of the world is contained in the carbonate reservoir. It is estimated that about 60% of the world’s oil and 40% of gas reserves are confined in carbonate reservoirs. Exploration and development of hydrocarbons in carbonate reservoirs are much more challenging due to poor seismic imaging and reservoir heterogeneity caused by diagenetic changes. Evaluation of carbonate reservoirs has been a high priority for researchers and geoscientists working in the petroleum industry mainly due to the challenges presented by these highly heterogeneous reservoir rocks. It is essential for geoscientists, petrophysicists, and engineers to work together from initial phases of exploration and delineation of the pool through mature stages of production, to extract as much information as possible to produce maximum hydrocarbons from the field for the commercial viability of the project. In the absence of the well-log data, the properties are inferred from the inversion of seismic data alone. In oil and gas exploration and production industries, seismic inversion is proven as a tool for tracing the subsurface reservoir facies and their fluid contents. In this paper, seismic inversion demonstrates the understanding of lithology and includes the full band of frequency in our initial model to incorporate the detailed study about the basin for prospect evaluation. 3D seismic data along with the geological & petrophysical information and electrologs acquired from drilled wells are used for interpretation and inversion of seismic data to understand the reservoir geometry and facies variation including the distribution of intervening tight layers within the Miocene carbonate reservoir in the study area of Central Luconia. The out-come of the seismic post-stack inversion technique shows a better subsurface lithofacies and fluid distribution for delineation and detailed study of the reservoir.

Carbonate reservoir evaluation and gas bearing prediction in Ordos Basin

In order to solve the problem that carbonate rocks are difficult to be explored due to their complex heterogeneity, the evaluation of carbonate reservoirs and the prediction of gas bearing are carried out. Firstly, taking the Sugeri gas field area in Ordos as an example, the address characteristics of the research area are introduced. Then the petrological characteristics and reservoir spatial characteristics (pore types and pore structures) of carbonate reservoirs are explored. In addition, the prediction and simulation method of carbonate reservoir gas bearing—amplitude variation with offset (AVO) forward modeling analysis method is discussed. Finally, the results of reservoir characteristics and prediction of reservoir gas bearing are analyzed. The results show that there is no effective reservoir development in Ma Wu32, Ma Wu33, and Ma Wu41b in the study area, and Ma Wu41a is the main effective reservoir development segment, followed by Ma Wu2 subsegment. For gas bearing prediction, there are a total of 10 favorable zones in Ma Wu segment, among which the predicted gas thickness is between 2 and 8 m. The results have good guiding significance for oil and gas exploration in China.

Pore type identification in carbonate rocks using convolutional neural network based on acoustic logging data

Existing methods of well logging interpretation often contain uncertainties in the exploration and evaluation of carbonate reservoirs due to the complex pore types. Based on the time–frequency analysis of array acoustic logging data, the identification of pore types based on a convolutional neural network (CNN) was established. The continuous wavelet transform was first used to transform the 1-D acoustic wave data into 2-D time–frequency spectra as the input data of the CNN based on the pore aspect ratios. According to the acoustic logging data obtained from numerical simulations, a three-type (vug, interparticle-pores, and crack) prediction was established to validate the identification method. The noise-sensitivity analyses demonstrate that our method is stable for noise mixed signals. The CNN-based identification method was used to analyze the field acoustic logging data in a carbonate reservoir. According to the description of the pore structures from the core analysis, the formation pores were divided into two types (cracks and interparticle-pores). The accuracy of the method using field acoustic logging data can reach 90%. This work provides promising means for pore type identification from complex acoustic logging data by applying deep learning technologies, which can be easily extended into other similar neighboring carbonate reservoirs.

NUMERICAL STUDY OF PORE STRUCTURE EFFECTS ON ACOUSTIC LOGGING DATA IN THE BOREHOLE ENVIRONMENT

Existing methods of well-logging interpretation often contain errors in the exploration and evaluation of carbonate reservoirs due to the complex pore structures. The differences in frequency ranges and measurement methods deviated between the acoustic well logs and indoor ultrasonic tests cause inconsistent results. Based on the elastic wave equation and the principle of the control variable method, a 2D axisymmetric borehole model with complex pore structures was developed, and the numerical simulation method for acoustic log was constructed. The modeling results show that the power function can well describe the effects of pore structure on the acoustic waves, while the velocity of the Stoneley wave is not sensitive to the pore structure. Crack-like pores with pore aspect ratio (AR) less than 0.1 significantly affect the velocities of P- and S-waves, whereas “spherical” pores have fewer effects. The models with larger pore sizes have high velocities of P- and S-waves. The velocities calculated by the equivalent medium theory are always higher than the numerical simulation results. The velocity deviation caused by the difference in frequency is much smaller than the pore structure. A fractal approach to quantify the effects of pore structures is applied in the acoustic logging data. The fractal dimension increases with the pore AR or size when the porosity is constant, which can be described by a simple power function. This gives us new ideas and methods for pore structure evaluation in the lower frequency range than the conventional petrophysical model.

Evolution Mechanisms of Carbonate Reservoirs Based on Dissolution Rates and Multifractal Analysis of Microscopic Morphology

Carbonates dissolution processes and their effects on the development of secondary pores play important roles in oil/gas exploration and development, which have been controversial for a long time. Dissolution experiments of carbonates are still challenging for studying the formation of micro-spaces evolution in carbonate reservoir rocks. In this paper, the chemical water–rock reaction experiments, microscopic morphology and multifractal analysis were used to study the dynamic dissolution of carbonate rocks on the Middle and Lower Ordovician of Tarim Basin, NW China. Measurements were made at temperatures of 40–150 °C and pressure of 40 atm in silicic acid solution and in NaCl solution at pCO2 during dissolution processes based on the rotating disk apparatus. The results show that the dissolution rate of carbonates varies with the temperatures during the dissolution process, corresponding to the early dissolution in the formation and the post-reformation of fluid of carbonates reservoirs. The range of “dissolution window” for each sample was calculated, and the burial depth of high-quality reservoirs was speculated. Compared to limestones, dissolution processes for dolomites could create more micro-spaces under deeper burial. Except regional geological conditions, the micro-spaces produced in dissolution processes of carbonates are also affected by the local topography of mineral arrangements and the element distribution singularities on the mineral surface. In addition, the phenomenon that burial dissolution created a significant number of secondary pores is conducive to the formation of high-quality reservoirs. Investigation of both the mechanism of dissolution and controlling factors of typical carbonates on the Middle and Lower Ordovician of the Tarim Basin, NW China, in this paper, provides new insights into the evaluation of carbonate reservoirs.

Determination of the Appropriate Value of m for Evaluation of Carbonate Reservoirs With Vugs and Fractures at the Well-Log Scale

Determination of the Appropriate Value of m for Evaluation of Carbonate Reservoirs With Vugs and Fractures at the Well-Log Scale

Application of overlapping probability method in carbonate reservoir evaluation: a case study on 4 th member of Shahejie Formation in Gaosheng area of western sag, Liaohe depression

Application of overlapping probability method in carbonate reservoir evaluation: a case study on 4 th member of Shahejie Formation in Gaosheng area of western sag, Liaohe depression

Prediction of fracture density using genetic algorithm support vector machine based on acoustic logging data

Existing methods of well-logging interpretation cannot be applied accurately for the exploration and evaluation of carbonate reservoirs because of the fracture development. Based on the fracture density obtained by core analysis in a carbonate reservoir located in the Ordos Basin, in northwest China, three types of fracture density (low fracture density, medium fracture density, and high fracture density) of the target formation were identified. We investigated the effect of fractures on acoustic logging signals in the time and frequency domains by the Hilbert-Huang transform (HHT) and extracted 11 features in the time domain and nine features in the frequency domain. Then, we reduced the features in the time and frequency domain to three principal components by principal component analysis. Finally, a new prediction model of genetic algorithm-support vector machine method based on HHT of acoustic logging data was reported to predict the fracture density. The results indicate that the fracture density has a greater effect on the attenuation of intrinsic mode function 2 (IMF2) and IMF3 components for three different types of formation by empirical-mode decomposition analysis. The energy of the Stoneley wave and S-wave has higher sensitivity than the P-wave. Compared with the time domain, the distribution in the high-frequency domain has a greater correlation with fracture density by the Hilbert spectrum and marginal spectrum. The correlation coefficients between the fracture density and nine features in the frequency domain ([Formula: see text]) are better than the coefficients with 11 features in the time domain ([Formula: see text]). The core analysis and interpretation of resistivity image logging support the validity and effectiveness of our model. The prediction accuracy using the features in the frequency domain can reach to 82%–90%, which is much higher than using the features in the time domain with accuracy of 52%–59%. The application with more information of original acoustic logging data in our model not only avoid the error in velocity picking but also point the direction for the future prediction.

A textural and diagenetic assessment of the Zechstein Limestone carbonates, Poland using the transverse Nuclear Magnetic Resonance relaxometry

As a consequence of carbonate pore system ambiguity, only two basic carbonate textures, i.e. mudstone and completely contrasting grainstone have thus far been found to be separable using Nuclear Magnetic Resonance (NMR) relaxometry. Therefore, a new methodology of NMR-derived carbonate facies and diagenetic alteration recognition was prepared and experimentally launched. As many ancient carbonates have often experienced a meteoric exposure stage, this approach focuses on such conditions. Especially the paleoreef carbonate reservoirs are of the main interest of the authors. The Wielichowo Reef (western Poland), developed on an uplifted pre-Zechstein horst structure - the Wolsztyn Ridge - was chosen for the study object. The reef is representative for its region because it is characterized by both high textural and diagenetic variability, often repeatable in case of other objects present on the Wolsztyn Ridge. Consequently, twenty one Zechstein Limestone (Ca1) carbonate core samples from the chosen object were qualitatively studied using a low-field, 50 [mT] NMR spectrometer. Corresponding thin section samples were carefully investigated using both polarizing and electron microscopy, cathodoluminescence and sample staining to obtain a full overview of their petrography and enable further comparisons between NMR and the remaining data. As shown by the obtained results, various carbonate facies can be distinguished on the basis of few criteria. These include: (1) the changeability of the signal's amplitude, (2) the values of clay-bound (MCBW), capillary (BVI) and freely moving (FFI) water, and (3) – the width of the main T2 peak, defined as the first peak occurring directly after the BVI, whose average amplitude exceeds or equals at least 75% of the maximal average amplitude encountered within MCBW or BVI systems. Similarly, it seems possible to separate dissolution vugs from other pore systems. The wider the main peak, the higher the probability of finding irregularly-shaped vugs, as diameter size variances account for elevating signal's amplitude, corresponding to various relaxation times. Furthermore, fractures and increased cementation have a significant impact on final T2 distribition's appearance, as well - hence making the low-field NMR an invaluable tool in the evaluation of carbonate reservoirs influenced by the meteoric exposure.

Fracture identification based on remote detection acoustic reflection logging

Fracture identification is important for the evaluation of carbonate reservoirs. However, conventional logging equipment has small depth of investigation and cannot detect rock fractures more than three meters away from the borehole. Remote acoustic logging uses phase-controlled array-transmitting and long sound probes that increase the depth of investigation. The interpretation of logging data with respect to fractures is typically guided by practical experience rather than theory and is often ambiguous. We use remote acoustic reflection logging data and high-order finite-difference approximations in the forward modeling and prestack reverse-time migration to image fractures. First, we perform forward modeling of the fracture responses as a function of the fracture–borehole wall distance, aperture, and dip angle. Second, we extract the energy intensity within the imaging area to determine whether the fracture can be identified as the formation velocity is varied. Finally, we evaluate the effect of the fracture–borehole distance, fracture aperture, and dip angle on fracture identification.