Heterogeneous Reservoir Rock Research Articles

True triaxial physics simulations and process tests of hydraulic fracturing in the Da’anzhai section of the Sichuan Basin tight oil reservoir

The limestone reservoir of the Da’anzhai section is the main production layer of Jurassic tight oil in central Sichuan, with tight and strongly heterogeneous reservoir rocks. In the early stages, small-scale plug removal and acidification techniques were mainly applied to the dacite section of the reservoir. However, using a single conversion method was not suitable for tight reservoirs with underdeveloped fractures. To address this challenge, we conducted large-scale real-world triaxial simulation test system experiments on hydraulic fracture propagation using samples from dense limestone outcrops. The aim was to elucidate the laws of hydraulic fracture propagation in dense limestone oil reservoirs. The L1 well in this area was selected to test the volumetric fracturing technology in order to achieve a breakthrough in test production and the reconstruction technology of the Da’anzhai section of the tight limestone reservoir. The experiments have shown that low stress differences, natural fracture development, and low viscosity slippery water are favorable factors for obtaining complex fracture morphology. In contrast to the construction parameters, the structural properties of the rock are the dominant factors in the formation of complex fracture morphologies. By optimizing the geological dessert and implementing targeted technological measures, bulk fracturing has been proven to be feasible for the dense limestone reservoir in the Da’anzhai section.

Influence of coal fly ash on the PPG properties and plugging ability in carbonate rocks for conformance control of oil reservoirs

The operation of explored reservoirs has become necessary due to the difficulty in achieving new and economically viable oil fields. However, the injected recovery fluids may flow on preferential paths in some heterogeneous reservoir rocks, which decreases the oil production efficiency. To avoid these problems, conformance control techniques have been used to optimize reservoir sweep. This process works redirecting the injected fluids to the lower permeability segments, which increase the sweep efficiency. In recent years, several studies of preformed particle gel (PPG) have been performed to reduce reservoir heterogeneity and enhance oil recovery. In this work, PPGs constituted by the partially hydrolyzed polyacrylamide (PHPA) crosslinked with polyethyleneimine (PEI), containing coal fly ash (CFA), were evaluated. The results indicated that the presence of CFA in PPGs enhanced elasticity, stability, and resistance to thermal degradation. The PPG injection into carbonate rock reduced core permeability by 96.78%, indicating their promising applications in oil reservoir conformance control.

How does capillary pressure affect the relative permeability curves of heterogeneous carbonate rocks?

The relative permeability and capillary pressure data are critically important in estimating reservoir parameters in reservoir behavior simulation and predicting its future performance. They are critically used in comprehensive studies and the preparation of development plans. Routinely in the industry, the relative permeability curves are either determined and corrected by the analytical methods (e.g., the JBN method) or history matching. In these methods, the capillary pressure effects are generally ignored. However, the fluid flow across the heterogeneous carbonate reservoir rocks is mainly controlled by the capillary effect due to their pore size distribution and the complex mixed wettability behavior. Consequently, considering both capillary and viscous impact and the other governing mechanisms in the extraction of fluid flow functions should be regarded as necessary, especially in heterogeneous media. The effect of the capillary pressure curve on the determination and correction methods of relative permeability has been rarely addressed in the literature. Moreover, in the complex behavior of the heterogeneous mixed-wet carbonate rocks, the impact of the wettability preference on the flow functions has not been frequently reported for the reservoir fluids and the modified fluids, such as in the case of IOR/EOR methods (e.g., low salinity, engineered water, and micellar methods). For this purpose, in this study, a series of capillary pressure and relative permeability tests have been performed on different carbonate plug samples. Then, the relative permeability curves of the plug samples were measured and corrected in two cases: Pc = 0 and Pc≠0 (concerning the centrifuge data), to investigate the relative permeability of both phases. The results indicated that the injection fluid and initial wettability of the rock are critically important parameters in considering the capillary pressure as a factor in the calculation and correcting of the relative permeability curves.

Discrete fracture modeling by integrating image logs, seismic attributes, and production data: a case study from Ilam and Sarvak Formations, Danan Oilfield, southwest of Iran

Understanding the fracture patterns of hydrocarbon reservoirs is vital in the Zagros area of southwest of Iran as they are strongly affected by the collision of the Arabian and Iranian plates. It is essential to evaluate both primary and secondary (fracture) porosity and permeability to understand the fluid dynamics of the reservoirs. In this study, we adopted an integrated workflow to assess the influence of various fracture sets on the heterogeneous carbonate reservoir rocks of the Cenomanian–Santonian Bangestan group, including Ilam and upper Sarvak Formations. For this purpose, a combination of field data was used including seismic data, core data, open-hole well-logs, petrophysical interpretations, and reservoir dynamic data. FMI interpretation revealed that a substantial amount of secondary porosity exists in the Ilam and Sarvak Formations. The upper interval of Sarvak 1-2 (3491 m to 3510 m), Sarvak 1-3 (3530 m to 3550 m), and the base of Sarvak 2-1 are the most fractured intervals in the formation. The dominant stress regime in the study area is a combination of compressional and strike-slip system featuring reverse faults with a NW–SE orientation. From the depositional setting point of view, mid-ramp and inner-ramp show a higher concentration of fractures compared to open marine environment. Fracture permeability was modeled iteratively to establish a realistic match with production log data. The results indicate that secondary permeability has a significant influence on the productivity of wells in the study area.

The Porosity in Heterogeneous Carbonate Reservoir Rocks: Tectonic versus Diagenetic Imprint—A Multi-Scale Study from the Hyblean Plateau (SE Sicily, Italy)

The petroleum industry has always been pursuing highly exploitable gas fields, which are often hosted in carbonate rocks. However, carbonates are highly heterogeneous and show different fabrics and structures as the result of sedimentation in various environments, and subsequent diagenesis and deformation. In this study, a multi-scale and multidisciplinary approach has been performed on classical reservoir rocks from the subsurface of the Hyblean Plateau (Sicily, Italy). We aim at unravelling the important and debated role of tectonic and diagenetic structures (mainly fractures as well as stylolites) in enhancing or reducing the porosity. Black shales, limestones, and laminites of intertidal environment represent the main lithologies. Structure cross-cutting relationships record different stages of the basin geological history, which are related to the tectonic evolution of the area. Our results show that porosity is uncommonly lightly affected by fractures and faults, because of their mineralization, whereas stylolites, which are often considered as barriers to fluid flow, show a certain porosity. Therefore, we want to highlight the importance of a multi-scale and multidisciplinary approach in the analysis of heterogeneously porous, fractured- and stylolite-rich carbonate rocks, and our study aspires to boost other similar gas reservoir studies in energy transition times.

Single or Multiple Porosity Cut Off A New Relevance Provided By Application of A New Approach

Porosity cut-off is one of the most important parameter normally used to differentiatebetween reservoir and non-reservoir rocks. Quantity of the parameter certainly dictatesreservoir volumes, hence directly influences economics and commerciality of a given oil/gas field. An ever critical issue in relation to this parameter is whether the use of porositycut-off has to be established through a single or multiple values especially for heterogeneousformation rocks. This certainly may lead to different reservoir sizes along with thetechnical and economical consequences. The study presented in this article is meant to furtherinvestigate this question. The thrust of this study lies on the application of a newlyproposed method for determining porosity cut-off. It is put that with this new and reliablemethod – compared to the traditionally used method – a more conclusive answer can beachieved. For the purpose, a heterogeneous limestone reservoir in West Java – Indonesiais used. Evaluation, analysis, and application of the new method on data from the field’seight wells have shown that multiple porosity cut-off values are needed for better definitionsof reservoirs. Application of a single value for these reservoirs can still be regardedas unrepresentative. The fact underlines that – despite the new approach’s reliability –heterogeneity governs more over the use of either single or multiple cut-off values ratherthan limitations of method. The study also proves that the new method for determiningporosity cut-off works well for highly heterogeneous reservoir rocks.

Rock physics templates for anisotropic and heterogeneous reservoir rocks considering mineralogy, texture and pore-filling fluid

Anisotropic Rock Physics Templates (RPTs) are efficient tools to interpret well logs. In this work, micromechanical modeling is used to calculate the effective properties of heterogeneous and anisotropic rocks due to the presence of fluid-filled aligned fractures or other minerals, e.g. clay, quartz and calcite. When the spheroidal inclusions are aligned, the transversely isotropic symmetry is described by Hill’s 5 elastic moduli, which are obtained after solving a system of nonlinear algebraic equations. New anisotropic Rock Physics Templates are based on these elastic moduli, in which it is easy to identify the presence of fluids in a reservoir. It has been observed that effective properties depend strongly on the aspect ratio of inclusions, pore fluid, and mineralogy. These new numerical results are similar to with others already published when the aspect ratio is set to 1. For aspect ratios δ of 0.25,0.5, and 0.75, these ternary plots give new elements of interpretation and analysis of results obtained either in a rock physics laboratory or in the field station. For instance, lower aspect ratios δ=0.5 until values nearly to δ=1 consider thick interbedded formations or fluid-filled pore under compaction. The latter will lead to a better characterization of the heterogeneous and anisotropic reservoir rocks, which are linked to producing commercial hydrocarbon areas. Herein, a shale gas reservoir is consistently identified by the proposed anisotropic RPTs.

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.

Improving the reliability of determining physical properties of heterogeneous clay reservoir rocks using a set of techniques

Oil-water-saturated formations of Western Siberian fields represented by polymictic sandstones are often characterized by strong granulometric heterogeneity. This is the reason for an incorrect assessment of the physicochemical properties of reservoirs, including wettability. On the example of the BS9 - BS11 formations of two fields of Surgut oil and gas region, the distribution of wettability of core samples was analyzed. An analysis of the modeling results for the hydrocarbon phase displacement by oil-saturated reservoir water was carried out using the Tulbovich method. To assess reliability of the wettability values, it was proposed to correlate the difference in the masses of water and kerosene displaced during capillary impregnation and centrifugation with differences in the mass of water and kerosene in water-and kerosene-saturated samples. The method was used to plot the distribution of porosity, permeability and relative clay content on the wettability parameter by capillary impregnation and centrifugal displacement. The results obtained were compared with similar dependences of the reservoir properties and clay content on the general wettability parameter. The type of wettability of core samples with good reservoir properties is validated in complex, low-permeability reservoirs with a high content of clay material. It is recommended to use the results of modeling the displacement by capillary impregnation and centrifugation with differences in the mass of water and kerosene.

Pore-Network Stitching Method: A Pore-to-Core Upscaling Approach for Multiphase Flow

Pore-network modeling is a widely used predictive tool for pore-scale studies in various applications that deal with multiphase flow in heterogeneous natural rocks. Despite recent improvements to enable pore-network modeling on simplified pore geometry extracted from rock core images and and its computational efficiency compared to direct numerical simulation methods, there are still limitations to modeling a large representative pore-network for heterogeneous cores. These are due to the technical limits on sample size to discern void space during X-ray scanning and computational limits on pore-network extraction algorithms. Thus, there is a need for pore-scale modeling approaches that have the natural advantages of pore-network modeling and can overcome these limitations, thereby enabling better representation of heterogeneity of the 3D complex pore structure and enhancing the accuracy of prediction of macroscopic properties. This paper addresses these issues with a workflow that includes a novel pore-network stitching method to provide large-enough representative pore-network for a core. This workflow uses micro-CT images of heterogeneous reservoir rock cores at different resolutions to characterize the pore structure in order to select few signature parts of the core and extract their equivalent pore-network models. The space between these signature pore-networks is filled by using their statistics to generate realizations of pore-networks which are then connected together using a deterministic layered stitching method. The output of this workflow is a large pore-network that can be used in any flow and transport solver. We validate all steps of this method on different types of natural rocks based on single-phase and two-phase flow properties such as drainage relative permeability curves of carbon dioxide and brine flow. Then, we apply the stochastic workflow on two large domain problems, connecting distant pore-networks and modeling a heterogeneous core. We generate multiple realizations and compare the average results with properties from a defined reference pore-network for each problem. We demonstrate that signature parts of a heterogeneous core, which are a small portion of its entire volume, are sufficient inputs for the developed pore-network stitching method to construct a representative pore-network and predict flow properties.

Liquid and Gas Corrected Permeability Correlation for Heterogeneous Carbonate Reservoir Rocks

Permeability is considered as an efficient parameter for reservoir modelling and simulation in different types of rocks. The performance of a dynamic model for estimation of reservoir properties based on liquid permeability has been widely established for reservoir rocks. Consequently, the validated module can be applied into another reservoir type with examination of the validity and applicability of the outcomes. In this study the heterogeneous carbonate reservoir rock samples of the Tertiary Baba Formation have been collected to create a new module for estimation of the brine permeability from the corrected gas permeability. In addition, three previously published equations of different reservoir rock types were evaluated using the heterogenous carbonate samples. The porosity and permeability relationships, permeability distribution, pore system and rock microstructures are the dominant factors that influenced on the limitation of these modules for calculating absolute liquid permeability from the klinkenberg-corrected permeability. The most accurate equation throughout the selected samples in this study was the heterogenous module and the lowest quality permeability estimation was derived from the sandstone module.

Estimation of Petrophysical Parameters from Seismic Inversion by Combining Particle Swarm Optimization and Multilayer Linear Calculator

In heterogeneous reservoir rocks, the accurate characterization of lithology and reservoir parameters is significant to minimize drilling risks and to improve oil and gas recoveries. In this work, a joint inversion strategy based on multilayer linear calculator (MLC) and particle swarm optimization (PSO) algorithm was applied to predict the spatial variations of key petrophysical (porosity, permeability, and saturation) and geomechanical parameters (Young’s modulus, Poisson’s ratio, and brittleness) for inter-well regions. In this method, acoustic impedance (AI) models are computed from post-stack seismic amplitude data by applying the proposed strategy (MLC + PSO) and back propagation neural network-based seismic inversion in the time domain with measured log density and velocity as constraints. The obtained results reveal that the proposed strategy, which combines MLC and PSO, leads to the optimization of lateral and vertical facies heterogeneities and accurate prediction of reservoir parameter distribution, i.e., the low AI is related to sand facies and corresponds to high porosity, permeability, saturation, and mid-range of Young’s modulus. The time slice maps of inverted porosity and permeability at various time intervals indicate a reasonable calibration with the measured core and well log data. The methodology proposed in this study may be considered useful for other basins in Pakistan with similar geological settings and anywhere in the world for reservoir characterization, particularly for intercalated shale and variable depositional environments.

Evaluation of the conventional and synchrotron X-ray tomography applied to heterogeneous oil reservoir rocks

Carbonate and sandstone reservoirs play an important role in oil industry as they host over 50% of the world’s hydrocarbon reserves. For an accurately assessment of porosity and pore size distribution of such complex pore-network, which affect directly the macroscopic characteristics of multiphase fluid flow, X-ray computed microtomography (micro-CT) emerges as a powerful tool. In contrast to lab-based X-ray micro-CT (XCT), synchrotron X-ray micro-CT (SXCT) images are commonly free of artefacts (i.e. beam hardening) and the unique properties of synchrotron sources enable the X-ray imaging of complex and heterogeneous materials in greater detail, with higher quality, and short acquisition time. This work reports results of cone beam computed microtomography (XCT) in comparison with synchrotron computed microtomography (SXCT) applied to very heterogeneous carbonate and sandstone reservoir rocks. We analyze the quality of the image generated in terms of detection of details and artefacts, the advantages and limitation of each technique, as well as features like contrast, sharpness, and signal-to-noise ratio (SNR). Although SXCT offers significant advantages over XCT, the latter gains in cost of operation, accessibility and user-friendliness.

Reservoir simulation study of enhanced oil recovery by sequential polymer flooding method

As a reservoir reaches depletion stage there will still be a varying amount of residual oil saturation in the reservoir pore volume that is too heavy to move and produced. This undesirable phenomenon occurs due to adverse mobility and/or viscosity ratio between displacing phase (water) and displaced phase (residual oil). A solution to that is polymer injection which has been considered as one of the most effective and successful method to improve oil recovery. Moreover polymer flooding also showed limited success when applied in heterogeneous reservoir. This is because single polymer injection cannot sweep entire porous media efficiently, therefore in this research work the effectiveness of sequential polymer injection is studied and compared with conventional single polymer injection. The reservoir property model was developed from the available well data of an example field using stochastic approach. From the base case two more property models were developed to cover the heterogeneity from slightly to very heterogeneous reservoir rock. The degree of heterogeneity was obtained for each property model using Dykstra-Parson technique. The magnitude of Dykstra-Parson coefficient for Slightly, Moderate and Very heterogeneous were 0.24, 0.59 and 0.69, respectively. Our results indicated that injecting polymers sequentially with varying in concentrations is an effective technique for enhanced oil recovery in heterogeneous reservoir rock. Cited as : Sidiq, H., Abdulsalam, V., Nabaz, Z. Reservoir simulation study of enhanced oil recovery by sequential polymer flooding method. Advances in Geo-Energy Research, 2019, 3(2): 115-121, doi: 10.26804/ager.2019.02.01

Pore-scale Imaging and Characterization of Hydrocarbon Reservoir Rock Wettability at Subsurface Conditions Using X-ray Microtomography

In situ wettability measurements in hydrocarbon reservoir rocks have only been possible recently. The purpose of this work is to present a protocol to characterize the complex wetting conditions of hydrocarbon reservoir rock using pore-scale three-dimensional X-ray imaging at subsurface conditions. In this work, heterogeneous carbonate reservoir rocks, extracted from a very large producing oil field, have been used to demonstrate the protocol. The rocks are saturated with brine and oil and aged over three weeks at subsurface conditions to replicate the wettability conditions that typically exist in hydrocarbon reservoirs (known as mixed-wettability). After the brine injection, high-resolution three-dimensional images (2 µm/voxel) are acquired and then processed and segmented. To calculate the distribution of the contact angle, which defines the wettability, the following steps are performed. First, fluid-fluid and fluid-rock surfaces are meshed. The surfaces are smoothed to remove voxel artefacts, and in situ contact angles are measured at the three-phase contact line throughout the whole image. The main advantage of this method is its ability to characterize in situ wettability accounting for pore-scale rock properties, such as rock surface roughness, rock chemical composition, and pore size. The in situ wettability is determined rapidly at hundreds of thousands of points. The method is limited by the segmentation accuracy and X-ray image resolution. This protocol could be used to characterize the wettability of other complex rocks saturated with different fluids and at different conditions for a variety of applications. For example, it could help in determining the optimal wettability that could yield an extra oil recovery (i.e., designing brine salinity accordingly to obtain higher oil recovery) and to find the most efficient wetting conditions to trap more CO2 in subsurface formations.

Pore-scale Imaging and Characterization of Hydrocarbon Reservoir Rock Wettability at Subsurface Conditions Using X-ray Microtomography.

In situ wettability measurements in hydrocarbon reservoir rocks have only been possible recently. The purpose of this work is to present a protocol to characterize the complex wetting conditions of hydrocarbon reservoir rock using pore-scale three-dimensional X-ray imaging at subsurface conditions. In this work, heterogeneous carbonate reservoir rocks, extracted from a very large producing oil field, have been used to demonstrate the protocol. The rocks are saturated with brine and oil and aged over three weeks at subsurface conditions to replicate the wettability conditions that typically exist in hydrocarbon reservoirs (known as mixed-wettability). After the brine injection, high-resolution three-dimensional images (2 µm/voxel) are acquired and then processed and segmented. To calculate the distribution of the contact angle, which defines the wettability, the following steps are performed. First, fluid-fluid and fluid-rock surfaces are meshed. The surfaces are smoothed to remove voxel artefacts, and in situ contact angles are measured at the three-phase contact line throughout the whole image. The main advantage of this method is its ability to characterize in situ wettability accounting for pore-scale rock properties, such as rock surface roughness, rock chemical composition, and pore size. The in situ wettability is determined rapidly at hundreds of thousands of points. The method is limited by the segmentation accuracy and X-ray image resolution. This protocol could be used to characterize the wettability of other complex rocks saturated with different fluids and at different conditions for a variety of applications. For example, it could help in determining the optimal wettability that could yield an extra oil recovery (i.e., designing brine salinity accordingly to obtain higher oil recovery) and to find the most efficient wetting conditions to trap more CO2 in subsurface formations.

Numerical analysis of the hydrofracturing behaviours and mechanisms of heterogeneous reservoir rock using the continuum-based discrete element method considering pre-existing fractures

The continuum-based discrete element method was applied to probe 3D hydrofracturing behaviours. The interaction between hydrofracturing cracks and pre-existing fractures was modelled. Glutenite, a typical heterogeneous rock, was numerically reconstructed using physical parameter tests, computed tomography and imaging processing methods. The effect of pre-existing fractures on hydrofracture propagation was characterized, and the effects of material heterogeneity and horizontal in situ stress differences on fracturing were characterised using fractal theory. Investigation of hydraulic fracture (HF) propagation in heterogeneous rock, and of the mechanism by which complex hydrofracturing crack networks form through numerical simulation, revealed four typical influencing factors. These four, namely mineral particles, in situ stress difference, natural fracture (NF) density, and NF aperture inside the glutenite, were analysed to determine their effect on the HF propagation pattern, and the mechanism of complex fracture network formation in glutenite was determined. A 3D fractal dimension was proposed to characterize the spatial distribution of complex fracture networks. With increasing aperture and density of NFs, the hydrofracturing crack network becomes more complex. Mineral particles hinder the propagation of HFs; analogously, the higher the volume percentage of mineral particles is; the more complex is the hydrofracturing crack network that forms. The HFs generate and propagate near the bilateral tips of the NFs. The HFs will propagate along the direction of maximum horizontal in situ stress, and they are prone to turn into a single crack with greater in situ stress difference. The 3D fractal dimensions were computed and quantitatively reflected the above phenomena.

Coupled experimental/numerical workflow for assessing quantitative diagenesis and dynamic porosity/permeability evolution in calcite-cemented sandstone reservoir rocks

Some of the world best hydrocarbon reservoirs (carbonates and siliciclastics) are also believed to be valuable for subsurface storage of CO2 and other fluids. Yet, these reservoirs are heterogeneous in terms of their mineralogy and flow properties, at varying spatial-temporal scales. Therefore, predicting the porosity and permeability (flow properties) evolution of carbonates and sandstones remains a tedious task. Diagenesis refers to the alteration of sedimentary rocks through geologic time, mainly due to rock-fluid interactions. It affects primarily the flow properties (porosity and permeability) of already heterogeneous reservoir rocks. In this project a new approach is proposed to calculate/quantify the influence of diagenetic phases (e.g. dissolution, cement plugging) on flow properties of typical sandstone reservoir rocks (Early Jurassic Luxembourg Formation). A series of laboratory experiments are performed in which diagenetic phases (e.g. pore blocking calcite cement in sandstone) are selectively leached from pre-studied samples, with the quantification of the petrophysical characteristics with and without cement to especially infer permeability evolution. Poorly and heavily calcite-cemented sandstone samples, as well as some intermediate cemented samples were used. The results show a distinctive dissolution pattern for different cementation grades and varying Representative Elementary Volumes (REVs). These conclusions have important consequences for upscaling diagenesis effects on reservoirs, and the interpretation of geochemical modelling results of diagenetic processes. The same approach can be applied on other type of cements and host-rocks, and could be improved by integrating other petrophysical analyses (e.g. petroacoustic, NMR).

Visual representation and characterization of three-dimensional hydrofracturing cracks within heterogeneous rock through 3D printing and transparent models

The heterogeneity of unconventional reservoir rock tremendously affects its hydrofracturing behavior. A visual representation and accurate characterization of the three-dimensional (3D) growth and distribution of hydrofracturing cracks within heterogeneous rocks is of particular use to the design and implementation of hydrofracturing stimulation of unconventional reservoirs. However, because of the difficulties involved in visually representing and quantitatively characterizing a 3D hydrofracturing crack-network, this issue remains a challenge. In this paper, a novel method is proposed for physically visualizing and quantitatively characterizing the 3D hydrofracturing crack-network distributed through a heterogeneous structure based on a natural glutenite sample. This method incorporates X-ray microfocus computed tomography (μCT), 3D printing models and hydrofracturing triaxial tests to represent visually the heterogeneous structure, and the 3D crack growth and distribution within a transparent rock model during hydrofracturing. The coupled effects of material heterogeneity and confining geostress on the 3D crack initiation and propagation were analyzed. The results indicate that the breakdown pressure of a heterogeneous rock model is significantly affected by material heterogeneity and confining geostress. The measured breakdown pressures of heterogeneous models are apparently different from those predicted by traditional theories. This study helps to elucidate the quantitative visualization and characterization of the mechanism and influencing factors that determine the hydrofracturing crack initiation and propagation in heterogeneous reservoir rocks.

Petrophysics Analysis for Reservoir Characterization of Upper Plover Formation in the Field “A”, Bonaparte Basin, Offshore Timor, Maluku, Indonesia

Hydrocarbon potential within Upper Plover Formation in the Field “A” has not been produced due to unclear in understanding of reservoir problem. This formation consists of heterogeneous reservoir rock with their own physical characteristics. Reservoir characterization has been done by applying rock typing (RT) method utilizing wireline logs data to obtain reservoir properties including clay volume, porosity, water saturation, and permeability. Rock types are classified on the basis of porosity and permeability distribution from routines core analysis (RCAL) data. Meanwhile, conventional core data is utilized to depositional environment interpretations. This study also applied neural network methods to rock types analyze for intervals reservoir without core data. The Upper Plover Formation in the study area indicates potential reservoir distributes into 7 parasequences. Their were deposited during transgressive systems in coastal environments (foreshore - offshore) with coarsening upward pattern during Middle to Late Jurassic. The porosity of reservoir ranges from 1–19 % and permeability varies from 0.01 mD to 1300 mD. Based on the facies association and its physical properties from rock typing analysis, the reservoir within Upper Plover Formation can be grouped into 4 reservoir class: Class A (Excellent), Class B (Good), Class C (Poor), and Class D (Very Poor). For further analysis, only class A-C are considered as potential reservoir, and the remain is neglected.