Tight Carbonate Research Articles

The effect of fracture networks on the vertical permeability of a tight carbonate reservoir analogue: laminites from the Crato Formation, NE Brazil

The structural characterization of fractures is crucial to understand the processes of fluid flow in tight reservoirs. This contribution focuses on the role played by vertical fractures on the permo-porosity properties of the Aptian tight carbonate sequence of the Crato Formation, Araripe Basin (NE Brazil). The study performed a structural analysis in two different scales: reservoir scale (approximately 19.000 m2) and outcrop scale (approximately 125 m2), focusing on the fracture networks in lacustrine laminates, which have been investigated as an analogue of carbonate facies observed within the pre-salt reservoir sequence of the marginal basins in Brazil. This study employed a combination of systematic outcrop-based fracture characterization involving digital outcrop models and mechanical stratigraphy analysis. To evaluate the influence of vertical fracture systems in the fracture porosity and the equivalent permeability we performed DFN (Discrete Fracture Network) models. We focused on vertical calcite-filled fractures, oriented in two principal directions: set 1 NNW-SSE and set 2 NE-SW. Each set shows different vertical linkage patterns due to the influence of the mechanical intervals. Results of the outcrop scale model show similar behaviour for both fracture porosity and equivalent permeability, indicating that storage capacity and fluid flow may not be affected by vertical linkage of fractures. The reservoir scale DFN models show that the fracture porosity was greater in models which consider through-going continuous fractures than in models that consider the segmentation (discontinuity) of vertical fractures. Considering the vertical connectivity of fractures, the equivalent horizontal permeability (Kxx and Kyy) showed similar values in both scale models. This implies that vertical segmentation of fractures does not impact fluid flow in horizontal directions. The calculated values of equivalent vertical fracture permeability (Kzz) at reservoir scale are one order of magnitude higher in the DFNs that consider continuous fractures. Our results suggested that vertically continuous fractures enhance preferential flow pathways allowing greater vertical fluid flow than segmented fracture networks in tight carbonate reservoirs.

Parameter evaluation method of tight carbonate reservoir using electrical imaging pores diameter spectrum

Currently, high-yield gas reservoirs have been discovered by exploring Lower Paleozoic tight carbonate oil and gas reservoirs in the Changqing area. These reservoirs, however, are impacted by subsequent karstification and diagenesis processes, leading to the formation of complex pore spaces with varying pore diameters ranging from microns to millimeters. Conventional well curves, with a resolution at the decimeter level, can only provide an overview of the reservoir porosity, making it challenging to evaluate the pore structure. On the other hand, electrical imaging logging data has a sampling interval of 0.1 inches and a resolution as fine as 5 mm, providing valuable information for pore structure evaluation in tight reservoirs. Since formation resistivity is influenced by factors like porosity, mud filtrate resistivity, and cementation, the cementation index serves as a reflection of the pore structure. Therefore, by calibrating the cementation index using data obtained from experiments at different scales, the pore structure parameters of tight carbonate reservoirs can be evaluated. This study conducted a comparison between numerous core experiments at various scales and both conventional and imaging log data. A method was proposed for extracting pore size distribution characteristics and calculating the pore size spectrum based on electrical imaging logging, ultimately leading to the establishment of a quantitative evaluation model for the pore structure of tight carbonate reservoirs. The results demonstrated improved accuracy and consistency in interpretation, as confirmed by well test data.

Estimation of pore structure and permeability in tight carbonate reservoir based on machine learning (ML) algorithm using SEM images of Jaisalmer sub-basin, India

Analyzing the pore structure in carbonate reservoirs plays a crucial role in predicting fluid flow characteristics within these formations. The goal of the study was to use machine learning techniques for pore structure analysis and estimation of permeability in carbonate reservoirs. We implemented these algorithms by examining 2D scanning electron microscope (SEM) images of carbonate samples from the Jaisalmer sub-basin captured at various magnifications. In the initial stage of the analysis, various binarization algorithms were applied to determine carbonate sample porosity. Among these algorithms, the MaxEntropy algorithm gave a porosity value closely aligned with those obtained through petrography analysis. We employed the watershed algorithm to find the pore network parameters of carbonate samples at various magnifications. We observed that changes in magnification affected pore network parameters, resulting in a reduction in pore size distribution, throat radius, and grain size. Subsequently, we employed the numerical lattice Boltzmann method (LBM) to estimate the permeability of carbonate samples and compared to values derived from well logs. We employed machine learning (ML) algorithms, specifically Artificial Neural Network (ANN) and Support Vector Machine (SVM), to predict the permeability of carbonate samples. The input features for these models were the pore network parameters, while the LBM permeability values served as the output. We examine the prediction performance of these methods against the measured LBM permeability by conducting the error analysis and the coefficient of determination (R2\\documentclass[12pt]{minimal} \\usepackage{amsmath} \\usepackage{wasysym} \\usepackage{amsfonts} \\usepackage{amssymb} \\usepackage{amsbsy} \\usepackage{mathrsfs} \\usepackage{upgreek} \\setlength{\\oddsidemargin}{-69pt} \\begin{document}$${R}^{2}$$\\end{document}) calculation. Our findings revealed that the ANN models outperformed the SVM models. Specifically, the ANN model displayed an impressive R2 value of 0.892, along with root mean square error (RMSE), mean squared error (MSE) and, mean absolute error (MAE) values of 1.927, 3.716 and 1.580, respectively. In contrast, the SVM model yielded an R2 value of 0.849, with RMSE, MSE and, MAE values of 2.324, 5.401 and, 2.166 respectively, when assessed on testing data of measured permeability. This study found that ANN is more dependable, robust, and precise than SVM in forecasting carbonate sample permeability.

Natural Fractures Help Unlock Tight Carbonates in Oman

_ This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper SPE 211336, “Natural Fractures Help Unlock Tight Carbonates: Redeveloping the Natih B Reservoir in a Giant Field in the Sultanate of Oman,” by Loic Bazalgette, Nawal Aamri, SPE, and Chris Field, Petroleum Development Oman, et al. The paper has not been peer reviewed. _ Within the stratigraphy of one of the largest fields in north Oman is the Natih B reservoir. The development of the reservoir has undergone several challenges over the past decades because of the complexity of the reservoir setting and difficulties in locating the natural fractures. Success in developing such tight carbonates depends on the integration of high-quality seismic, borehole imagery, petrophysics, and dynamic data. The objective of the complete paper is to develop an integrated technical approach that can be used to unlock one of the largest undeveloped resources in the operator’s current portfolio. Introduction With approximately 1 billion bbl of oil originally in place in the development area of interest, Natih B is a significant undeveloped resource in the operator’s portfolio. Attempts were made during the 1980s and 1990s to produce from Natih B, but production was uneconomical because of low productivity or early gas breakthrough. The low matrix permeability of Natih B organic-rich carbonates negatively affected the flow of the early Natih B producers, but the presence of large-scale, vertically persistent fracture corridors and fault-damage zones allowed gas from the Natih A reservoir above to shortcut into these wells. The opportunity to redevelop Natih B was initiated in late 2018. The initiative involved a tight collaboration between the operator’s fractured-reservoir specialist and subject-matter experts of the structural geology of fractured reservoirs and of carbonate reservoir geology. Overview of Natih B Properties The Natih carbonate reservoir is composed of multiple units named Natih A, B, C, D, E, F, and G from top to bottom. In the field of interest, these are structured as a fault-bounded, northeast-dipping monocline (Fig. 1). In this structure, the reservoir is shallow. The initial reservoir pressure is 61 bar at 400 m true vertical depth subsea (TVDSS). All reservoir units are in pressure communication through cross-cutting fracture corridors and have a common free water level at approximately 550 m TVDSS. Current production is from all reservoir units with the exception of Natih B. In the outcrops of the Salakh Arch area (north Oman), the Natih B unit is divided into five subunits. Under Natih B reservoir conditions, this subdivision scheme can be simplified to four well-correlatable subunits with relatively small thickness variations (Natih B1 to B4). In the area of interest, the subunit thickness is approximately 15 m for B1, 30 m for B2, 10–15 m for B3, and 15–20 m for B4. Facies show a cyclicity of clean limestone and organic-rich layers, which is more pronounced in the B1 and B2 subunits. Natih B4 isolates the Natih B reservoir unit from the underlying Natih C reservoir. Above the free water level, the porosity of Natih B subunits B1, B2, and B3 ranges generally between 0.15 and 0.30. The permeability of Natih B is low and ranges from 0.2 to 5 md, with an average of approximately 1 md.

Improving oil and gas flowability in tight carbonates with a novel solid delayed acid

The economic development of tight carbonate reservoirs requires hydraulic or acid fracturing stimulation. Acid fracturing better activates natural fractures, resulting in increased stimulated reservoir volume and improving oil and gas flowability. In order to solve the problem of excessive acid-rock reaction due to high temperature, this paper screened four kinds of solid forms of acid with the maximum quantity of acid and reaction rate as the index and formed a high temperature-resistant mixed solid acid system with solid organic acid as the main part and inorganic solid acid as the auxiliary part. The maximum quantity of acid produced and effective acid concentration of the system were greater than 50%, and no residue was precipitated after the complete reaction. Dynamic acid-rock rate tests were performed on different types of retarded acid at 140 °C. The test results show that the solid acid dissolves to form a low-viscosity acid solution, and the reaction rate is one order of magnitude lower than that of gelled and cross-linked acids at the same hydrogen ion concentration, and it is little affected by temperature. Moreover, the paper compares the treatment effect of micro-proppants and solid acids on micro-fractures. The results show that the core permeability improvement multiples up to 900 times under low dissolution of solid acid and the formation of oil and gas flow channels with the same scale as micro-proppants. The experimental results demonstrated the ability of solid delayed acid to transport the fracture leading edge at high temperatures and effectively activate micro-fractures.

Spectrum of Nanopores, Micropores, and Associated Pore Networks and their Origins in Carbonate Strata

Nano- and micropores (defined as pores less than 10 μm in diameter) are common in carbonate reservoirs as either the sole pore type or in combination (dual pore networks) with matrix macropores and fracture pores. These very fine-scale pores form in limestones and dolostones and in associated organic matter (e.g., solid bitumen). Limestone nano- and micropores occur between crystals that are commonly less than 1 to 9 μm in size in limestone, but in dolostone the crystal size can be much larger. Limestone nano- and micropores commonly originate in three ways, although some inherited original nano- and micropores between mud components are preserved. First, in original lime-mud mixtures of aragonite, Mg–calcite, and calcite, the origin is both depositional and diagenetic as aragonite dissolves and reprecipitates because microrhombic calcite, Mg–calcite transforms to microrhombic calcite, and original calcite grains are generally unaffected. Second, in chalks, nano-and micropores are related to the original depositional fabric as interparticle pores between coccoliths and other pelagic allochems. Third, in sediment originally composed of Mg–calcite-rich allochems, nano-and micropores form by transformation of unstable Mg–calcite allochems to microrhombic calcite. In dolostones, nano-and micropores are associated with extensive dolomitization and the nearly complete occlusion of pores (overdolomitization), whereas another diagenetic origin in dolostones is differential dolomitization at the grain scale. Also, in some dolostones, nano- to micropores pores are inherited from precursor microporous limestone. A late process of nano- and micropore formation is subaerial weathering of both limestones and dolostones resulting in pulverulite. This form of micropores is commonly developed at unconformities as enhanced porosity zones. Organic-matter nano- and micropores in solid bitumen, common in thermally mature organic-rich argillaceous limestone, can also be present in coarser-grained carbonates in which solid-bitumen occurs within macropores. Only in organic-rich limestones do organic-matter pores have potential to form an effective pore system. Because nano- and micropores have multiple origins, their lateral and vertical distribution reflects or depends on their origin; therefore, one must not only describe nano- and micropores, but also define their origin. Recognition of nano- and micropores is important because they form tight carbonate reservoirs and have significant effects on permeability, porosity perseveration with burial, hydrocarbon saturation, hydrocarbon recovery, sweep efficiency, storage, and reserve estimations. Not recognizing nano- and micropore networks can lead to errors relative to the aforementioned measurements and as a result, economic evaluations may be invalid.

Dating the late Miocene marine sediments around the southern middle Durance valley (Provence, SE France): new evidences for a Tortonian age

The present study aims dating the topmost 50 m of a 115 m-long core retrieved from a valley located in the Cadarache Area (Upper Provence, South East France). Based on burial dating by in situ produced cosmogenic nuclides (10Be, 26Al and 21Ne), and paleomagnetic analyses, a Tortonian age was determined for the sedimentary succession exhibited in the core. In addition, thin sections, grain size analyses and quartz morphoscopy were used to characterize a shallow marine environment and to correlate the sediment core to the surrounding exposed sections. When comparing the studied sedimentary record to global sea level estimates, we establish that the local Tortonian transgression was not synchronous with the global scale sea level high-stand, but happened more likely later, during a global regressive trend. The timing of the Tortonian flooding in Upper Provence was therefore most probably driven by regional tectonic forcing. Finally, the Tortonian shallow marine sediments are topped by lacustrine tight carbonates. These carbonates protect the marine sediments from the following major erosional events resulting from the Messinian sea level drop and from interglacial-glacial fluctuations that both yielded to the present-day valley topography.

A new nuclear magnetic resonance-based permeability model based on two pore structure characterization methods for complex pore structure rocks: Permeability assessment in Nanpu Sag, China

The nuclear magnetic resonance (NMR) estimate of permeability is a fundamental method that has numerous applications in reservoir engineering and petrophysics. To improve the accuracy of the NMR-based permeability model, many variables are introduced into NMR-based permeability prediction models due to geometric complexity and pore structure heterogeneity. In this paper, two pore structure characterization methods are investigated based on the Kozeny-Carman model and equivalent component model. Furthermore, an NMR-based permeability model accounting for the effect of pore structure is developed based on the analysis of the relationship between two pore structure parameters, and it is applied to practically predict permeability. Results indicate that the new model-calculated permeability has good agreement with experimental data; moreover, the adaptability of the new NMR-based permeability prediction model is highly improved through reducing undetermined variables, and key parameters can be measured directly using NMR. The new model provides a valuable scientific resource and assists in the evaluation of hydrocarbon-bearing reservoirs with complex pore structure, such as tight sandstone, shale, and carbonate rock.

CFD estimation of gas production in tight carbonates using single and dual-porosity models

Tight Carbonate reservoirs are regarded as one of the most complex reservoir formations due to the heterogeneity and complexity of their mineral composition, pore structure, and storage model. It is uncommon to study the implementation of a transport model appropriate for such formation. Recent studies focused on tight reservoirs and developed models for shale or coal bed methane reservoirs. This study proposes a single and dual-porosity transport model that solely considers the tight matrix and acidized region to shed light on the transport models for tight carbonates. The numerical model included the effect of transport mechanisms such as Knudsen diffusion, desorption, and viscous flow. The proposed transport model includes the apparent permeability model defining these transport mechanisms. Finite element method analysis was conducted on the numerical model using COMSOL Multiphysics. Due to the presence of nanopores in both shale and tight Carbonate, transport models proposed for the former can be utilized to determine the fluid flow behavior in the latter. The adsorption isotherm, rock density, pore structure, porosity, and permeability of the tight carbonate reservoir, which contrasted with the shale results, were the defining features of the reservoir used in the transport model. The dual-porosity model yielded a peak production of 104,000 m3/day, whereas the proposed model represents a shallow production rate from the single-porosity reservoir. The results were validated with an analytical solution proposed in the literature. Based on the literature findings and the production profile, the desorption did not play a significant role in the total production due to calcite’s low affinity towards CH4.

Experimental investigation of the impacts of supercritical carbon dioxide on acid-etching fracture morphology and conductivity in tight carbonate reservoir

Carbon dioxide (CO2) as energized fluid has been used for acid-fracturing in tight carbonate reservoir. CO2 is often pumped into the wellbore in liquid phase with acid systems, and transited into supercritical state under the high-temperature formation. While the effect of supercritical CO2 (SC-CO2) on acid-etched fracture morphology and conductivity have rarely been investigated. The acid-etching and conductivity experiments were conducted on the outcrops of the Ma5 sub-member of the Ordo Basin in China. The mixed phase reaction simulation device was developed firstly. These experiments involved the mixing of SC-CO2 with various fluids, including formation water and viscoelastic surfactant (VES) acid, as well as different SC-CO2 concentrations with VES acid. The results show that 100 % SC-CO2 is easy to activate natural fractures without dissolution. After 20%SC-CO2 mixed with formation water, the dissolution ability of the mixed solution and conductivity is only 11.8 % and 1 ∼ 2 % of VES acid respectively. Roughness of the morphology created by the mixture of SC-CO2 with VES acid, exhibits a reduction compared to VES acid-etching, accompanied by the presence of wormholes. Additionally, there is a decrease in conductivity and increase in its retention rate. With the increase of SC-CO2 concentration, the roughness of acid-etching fracture decrease and the injection pressure curve becomes more stable. While the reaction rate is also retarded nearly linearly as the SC-CO2 concentration increases. Especially, when the SC-CO2 concentration is up to 40 %, the acid-rock reaction rate reaches only 55 % of that of VES acid. The conductivity of mixed-acid-etched fracture exhibits a segmented characteristic. During the low-medium closure pressure stage, the acid-etched fracture by VES acid generates high conductivity, specifically when it is below 34.5 MPa. While the higher the SC-CO2 concentration in the mixed acid is, the greater the conductivity and retention rate are at pressures above 34.5 MPa during high closure pressure stage. The conductivity of SC-CO2 acid-fracturing fracture depends on the non-uniform etching of the acid solution. The increase in SC-CO2 concentration of the mixed acid not only enhances conductivity and retention rate under high closure pressure, but also reduces the acid volume required for acid-fracturing.

Control of strike-slip faults on Sinian carbonate reservoirs in Anyue gas field, Sichuan Basin, SW China

The largest Precambrian gas field (Anyue gas field) in China has been discovered in the central Sichuan Basin. However, the deep ancient Ediacaran (Sinian) dolomite presents a substantial challenge due to their tightness and heterogeneity, rather than assumed large-area stratified reservoirs controlled by mound-shoal microfacies. This complicates the characterization of “sweet spot” reservoirs crucial for efficient gas exploitation. By analyzing compiled geological, geophysical and production data, this study investigates the impact of strike-slip fault on the development and distribution of high-quality “sweet spot” (fractured-vuggy) reservoirs in the Ediacaran dolomite of the Anyue gas field. The dolomite matrix reservoir exhibits low porosity (less than 4%) and low permeability (less than 0.5×10−3 μm2). Contrarily, fractures and their dissolution processes along strike-slip fault zone significantly enhance matrix permeability by more than one order of magnitude and matrix porosity by more than one time. Widespread “sweet spot” fracture-vuggy reservoirs are found along the strike-slip fault zone, formed at the end of the Ediacaran. These fractured reservoirs are controlled by the coupling mechanisms of sedimentary microfacies, fracturing and karstification. Karstification prevails at the platform margin, while both fracturing and karstification control high-quality reservoirs in the intraplatform, resulting in reservoir diversity in terms of scale, assemblage and type. The architecture of the strike-slip fault zone governed the differential distribution of fracture zones and the fault-controlled “sweet spot” reservoirs, leading to wide fractured-vuggy reservoirs across the strike-slip fault zone. In conclusion, the intracratonic weak strike-slip fault can play a crucial role in improving tight carbonate reservoir, and the strike-slip fault-related “sweet spot” reservoir emerges as a unique and promising target for the efficient development of deep hydrocarbon resources. Tailored development strategies need to be implemented for these reservoirs, considering the diverse and differential impacts exerted by strike-slip faults on the reservoirs.

Stochastic seismic inversion and Bayesian facies classification applied to porosity modeling and igneous rock identification

We apply stochastic seismic inversion and Bayesian facies classification for porosity modeling and igneous rock identification in the presalt interval of the Santos Basin. This integration of seismic and well-derived information enhances reservoir characterization. Stochastic inversion and Bayesian classification are powerful tools because they permit addressing the uncertainties in the model. We used the ES-MDA algorithm to achieve the realizations equivalent to the percentiles P10, P50, and P90 of acoustic impedance, a novel method for acoustic inversion in presalt. The facies were divided into five: reservoir 1, reservoir 2, tight carbonates, clayey rocks, and igneous rocks. To deal with the overlaps in acoustic impedance values of facies, we included geological information using a priori probability, indicating that structural highs are reservoir-dominated. To illustrate our approach, we conducted porosity modeling using facies-related rock-physics models for rock-physics inversion in an area with a well drilled in a coquina bank and evaluated the thickness and extension of an igneous intrusion near the carbonate-salt interface. The modeled porosity and the classified seismic facies are in good agreement with the ones observed in the wells. Notably, the coquinas bank presents an improvement in the porosity towards the top. The a priori probability model was crucial for limiting the clayey rocks to the structural lows. In Well B, the hit rate of the igneous rock in the three scenarios is higher than 60%, showing an excellent thickness-prediction capability.

An improved Klinkenberg permeability model for tight reservoir cores: Effects of non-linear gas slippage to real gases

Absolute permeability is one of the most fundamental reservoir-rock properties required for reservoir simulation models. Most research studies are focused on the Klinkenberg gas slippage, considering the ideal behavior of the flowing gas under first- and second-order slippage conditions. This paper assesses the non-linear slippage of real gas through the low permeability reservoir rock samples. The cubic equation of state (van der Waals/Soave-Redlich-Kwong/Peng-Robinson), coupled with Taylor series-based non-linear slippage, predicts the apparent permeability for the non-Darcy gas flow in tight reservoir rock. The novelty of the present contribution is to develop a comprehensive mathematical model to describe the temperature- and pressure-dependent non-linear slippage effect accounting for the real gas behavior, which is based on the fundamental principle of momentum balance. The thirty-nine sets of experimental results of different authors using different core samples (e.g., coal seams, tight sandstones, tight carbonates, gas-shale reservoirs) and gases (Air, H2, He, N2, CH4, C2H6, and CO2) are used to authenticate the proposed non-linear slip model for real gases. Results show that (a) the proposed model correctly predicts infinite permeability and non-linear slippage coefficients of eight-tests non-ideal gases with an average absolute deviation of ≤9.69%, (b) non-linear slippage dominates for the core samples having permeability <1.5 mD, and (c) the first- and second-order slippage coefficients vary from 0.76 to 6.22 atm and 0.15–9.30 atm2, respectively. The proposed model is simple and may readily be applied for the reservoir simulation of coal seams, tight sandstones, tight carbonates, gas-shale reservoirs, etc., for reservoir characterization, forecasting future natural gas production, decision-making, and efficient reservoir management practices for enhanced production efficiency and sustainability.

Qualitative and quantitative diagenetic modelling in a tight carbonate reservoir in north-western Iraq

The diagenetic history of the Butmah Formation (Lower Jurassic) is very complex and affected by several diagenetic processes that worked effectively with fracturing control to create the final pore network. A microscopic study, core plug and well log analyses were combined in this study in order to describe, and differentiate between, the diagenetic and fracturing control that created the final pore system of the formation. The diagenetic processes of the Butmah Formation were studied in depth to describe the diagenetic stages and identify the elements that may compose a petrodiagenetic pathway illustrating its effect on the reservoir quality of the Butmah Formation. Accordingly, the Butmah Formation samples were divided into three petrophysical fields controlled mainly by fracturing and diagenesis, which were then used to develop a new method for estimating the pre-dolomitisation petrophysical properties of the dolomite samples and the post-dolomitisation petrophysical properties of the limestone samples. Consequently, the output of applying this method allows us to effectively begin to predict each of the elements that may compose a petrodiagenetic pathway for the Butmah Formation and make its reservoir characterisation integrated and more understandable. The new method provided a good prediction of matrix porosity and permeability, as well as allowing the estimation of reservoir properties of any other carbonate reservoir in petroleum development projects when there are no core samples in some formation intervals within boreholes.

A comprehensive review of viscoelastic polymer flooding in sandstone and carbonate rocks

Polymer flooding is a proven chemical Enhanced Oil Recovery (cEOR) method that boosts oil production beyond waterflooding. Thorough theoretical and practical knowledge has been obtained for this technique through numerous experimental, simulation, and field works. According to the conventional belief, this technique improves macroscopic sweep efficiency due to high polymer viscosity by producing moveable oil that remains unswept after secondary recovery. However, recent studies show that in addition to viscosity, polymer viscoelasticity can be effectively utilized to increase oil recovery by mobilizing residual oil and improving microscopic displacement efficiency in addition to macroscopic sweep efficiency. The polymer flooding is frequently implemented in sandstones with limited application in carbonates. This limitation is associated with extreme reservoir conditions, such as high concentrations of monovalent and divalent ions in the formation brine and ultimate reservoir temperatures. Other complications include the high heterogeneity of tight carbonates and their mixed-to-oil wettability. To overcome the challenges related to severe reservoir conditions, novel polymers have been introduced. These new polymers have unique monomers protecting them from chemical and thermal degradations. Monomers, such as NVP (N-vinylpyrrolidone) and ATBS (2-acrylamido-2-methylpropane sulfonic acid), enhance the chemical resistance of polymers against hydrolysis, mitigating the risk of viscosity reduction or precipitation in challenging reservoir conditions. However, the viscoelasticity of these novel polymers and their corresponding impact on microscopic displacement efficiency are not well established and require further investigation in this area. In this study, we comprehensively review recent works on viscoelastic polymer flow under various reservoir conditions, including carbonates and sandstones. In addition, the paper defines various mechanisms underlying incremental oil recovery by viscoelastic polymers and extensively describes the means of controlling and improving their viscoelasticity. Furthermore, the polymer screening studies for harsh reservoir conditions are also included. Finally, the impact of viscoelastic synthetic polymers on oil mobilization, the difficulties faced during this cEOR process, and the list of field applications in carbonates and sandstones can also be found in our work. This paper may serve as a guide for commencing or performing laboratory- and field-scale projects related to viscoelastic polymer flooding.

Petrophysical Analysis Based on Well Logging Data for Tight Carbonate Reservoir: The SADI Formation Case in Halfaya Oil Field

Carbonate reservoirs are an essential source of hydrocarbons worldwide, and their petrophysical properties play a crucial role in hydrocarbon production. Carbonate reservoirs' most critical petrophysical properties are porosity, permeability, and water saturation. A tight reservoir refers to a reservoir with low porosity and permeability, which means it is difficult for fluids to move from one side to another. This study's primary goal is to evaluate reservoir properties and lithological identification of the SADI Formation in the Halfaya oil field. It is considered one of Iraq's most significant oilfields, 35 km south of Amarah. The Sadi formation consists of four units: A, B1, B2, and B3. Sadi A was excluded as it was not filled with hydrocarbons. The structural and petrophysical models were built based on data gathered from five oil wells. The data from the available well logs, including RHOB, NPHI, SONIC, Gamma-ray, Caliper, and resistivity logs, was used to calculate the petrophysical properties. These logs were analyzed and corrected for environmental factors using IP V3.5 software. where the average formation water resistivity (Rw = 0.04), average mud filtrate resistivity (Rmf = 0.06), and Archie's parameters (m = 2, n = 1.9, and a = 1) were determined. The well-log data values calculated the porosity, permeability, water saturation, and net-to-gross thickness ratio (N/G).

The synergistic effects of cationic surfactant and smart seawater on the recovery of medium-viscosity crude oil from low-permeability carbonates

In the petroleum industry, there is a continuous search for cost-effective enhanced oil recovery (EOR) methods to increase oil extraction. Surfactant-based EOR is one of these effective methods, which is applied after the primary and secondary recovery phases. This paper presents an experimental study on the use of a cationic surfactant, hexadecyltrimethylammonium bromide (CTAB, CH3(CH2)15N(Br)(CH3)3), and smart seawater (SW) for EOR in low-permeability carbonate rock with medium viscosity crude oil. Smart SW was prepared by modifying the concentrations of Ca2+, Mg2+, and SO42- in synthetic offshore SW. The aqueous stability of CTAB was tested in different salinities of smart SW at the reservoir temperature. It was demonstrated that CTAB is stable at 55 °C, which was further confirmed through optical transmittance measurements, revealing values mostly exceeding 93%. The use of smart SW and CTAB significantly altered the wettability of carbonate rock towards water-wet and reduced the interfacial tension (IFT) between crude oil and water, reaching levels below 0.087 mN/m. However, the presence of smart SW increased the adsorption of CTAB onto the surface of carbonate rock. Nevertheless, the adsorption values were significantly below 1 mg/g-rock. Smart SW + CTAB resulted in a total oil recovery of 76.71% of original oil-in-place (OOIP), compared to 71.70% of OOIP with unmodified SW + CTAB. These results suggest that the use of smart SW in combination with CTAB is a promising approach for enhancing the recovery of medium-viscosity oil from tight carbonate reservoirs. Findings from this study can help in better understanding the optimal conditions for the application of smart SW-CTAB flooding to improve the effectiveness of tertiary recovery operations in the upstream oil sector.

Anatomy of fractures: Quantifying fracture geometry utilizing X-ray computed tomography in a chalk-marl reservoir; the Lower Cretaceous Valdemar Field (Danish Central Graben)

Naturally fractured reservoirs tend to show heterogeneous permeability with open fractures enhancing the inherent diagenetic and depositional matrix fabric. Natural open fractures may function as pathways for fluid flow in tight (low matrix permeability) carbonate reservoirs and have a significant impact on the directions, magnitudes and heterogeneities of fluid flow and reservoir rock strength. Open fractures may however also facilitate the invasion of formation water while fractures that are partially or completely cemented can act as barriers to fluid flow. As a result, natural fractures significantly impact reservoir flow rates, anisotropy, storage, connectivity, recovery, and production. X-ray Computed Tomography (CT) offers a non-destructive technique to evaluate petrophysical parameters, such as porosity and permeability, and to assess the geometry, connectivity, and density of natural fractures, which are important constituents of chalk reservoirs. The purpose of this study is to investigate different types of naturally occurring fractures within the Lower Cretaceous succession of the Valdemar Field in the Danish North Sea. Six samples of core displaying at least one natural fracture on the surface are imagined; two samples of open fractures with plumose structure and hackle marks, three samples of shear fractures and finally one sample with deformation bands. The samples are imaged by CT and internal fractures are manually mapped. Image analysis provides detailed information on the fracture geometry in addition it indicates the presence of numerous microfractures hitherto not recorded in the Lower Cretaceous of the Danish North Sea. Core data show that fracture intensity can be significantly greater than calculated by conventional core interpretation techniques based on core surface observations. Further, apertures of both major and minor fractures are measured in CT images of all samples to determine if specific fracture types display characteristic that can distinguish them from other fracture types. As open fracture intensity increases, so too does permeability, likely enhancing reservoir connectivity on the field scale.

Azimuthal Prestack Seismic Anisotropic Inversion on a Deep and Tight Carbonate Reservoir From the North Potwar Basin of Pakistan

Summary Quantitative characterization of deep, tight, and heterogeneous reservoirs plays an important role in identifying hydrocarbon pathways for effective and optimal reservoir field development. In this case study, we used an azimuthal prestack seismic anisotropic inversion approach to estimate attributes of horizontal transverse isotropy (HTI) caused by a set of vertical fractures, oriented cracks, and stress. Anisotropic inversion facilitated the conversion of interface properties to the corresponding layer-based properties, which led to the quantitative interpretation of reservoir properties related to azimuthal variation in seismic amplitudes. To estimate the anisotropy magnitude and the direction of the isotropy axis in HTI media, elastic properties (P-impedance and Vp/Vs) obtained from prestack seismic inversion (using six azimuth × four angle stack) served as inputs. The isotropic low-frequency model (LFM) is used as the foundation of the inversion for all azimuths, and the anisotropy effects are later added by updating the model along the azimuths. The direction of the isotropy plane resulting from the anisotropic inversion is determined by using the maximum horizontal stress as a prior constraint, which eliminates any inherent uncertainty. The workflow used effectively characterized the orientation and density of fractures from the recently discovered oilfield reservoirs of the Paleocene (Lockhart) formation located in Pakistan’s north Potwar Basin. It also helped improve the prediction accuracy for fractures in the study area. According to the observations (fractures) from the exploratory drilled well (D1) in the tight carbonate (Lockhart) reservoir, a significant amount of anisotropy magnitude is observed. This provides the basis for hydrocarbon exploration, field development, and reliable drilling decisions.

Pore structure and fluid mobility of tight carbonate reservoirs in the Western Qaidam Basin, China

AbstractTight carbonate reservoirs in the Western Qaidam Basin have complex lithologies and pore structures. The oil–water mobility law in reservoirs has not yet been completely determined, restricting the formulation of rational reservoir development methods. To bridge this gap, in this study, we used several test methods, such as casting thin sections, mercury intrusion, and nuclear magnetic resonance, to obtain the pore structure and oil–water displacement characteristics of tight carbonate reservoirs in the Western Qaidam Basin. The pore structures of the reservoirs could be categorized into three types: microfractures + dissolved pores + micropores (MFD), microfractures + micropores (MF), and matrix (M). The characteristics of single‐phase oil seepage and water flooding in reservoirs with various pore structures differed evidently. For the MF‐ and M‐types, the water‐locking effect caused by the strong capillary force affected oil charging in the micropores. The effect of the pressure drop on the MFD‐type algal limestone was less than that on the MF‐type limestone (dolomite) because of the occurrence of a non‐Darcy flow. The MFD‐type, which contained microfractures, had preferential seepage channels, resulting in obvious fluid channeling and low water displacement efficiency. Oil−water displacement mainly occurred in the dissolved pores and microfractures, suggesting that starting oil accumulation in the micropores was crucial. This study will assist in efficient development of tight carbonate reservoirs in the Western Qaidam Basin.