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Comparison of different gravity drainage options in the history-matching results for the bottom hole pressure (BHP) in eight wells. The lower bottom hole pressure response (the blue line) represents the reservoir behavior when the gravity neglected while the other overlapped lines represent the different gravity drainage formulas.
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Gravity drainage is one of the essential recovery mechanisms in naturally fractured reservoirs. Several mathematical formulas have been proposed to simulate the drainage process using the dual-porosity model. Nevertheless, they were varied in their abilities to capture the real saturation profiles and recovery speed in the reservoir. Therefore, und...
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This study presents a neural network which uses filters based on logistic mapping (LogNNet). LogNNet has a feedforward network structure, but possesses the properties of reservoir neural networks. The input weight matrix, set by a recurrent logistic mapping, forms the kernels that transform the input space to the higher-dimensional feature space. T...
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... Such transformations are particularly significant in carbonate rocks, which are highly sensitive to fluid-mineral interactions (e.g., Beaudoin et al., 2022;Fournier and Borgomano, 2009;Hiatt and Pufahl, 2014;Munoz-Lopez et al., 2022). Carbonate rocks form important economic reservoirs (Mazzullo, 2004;Rashid et al., 2022), and their study is of major interest for numerous applications such as gas sequestration, appraisal and development of hydrocarbons and water resources (Aljuboori et al., 2019;Bense et al., 2013;Eliebid et al., 2018;Kampman et al., 2012;Manzocchi et al., 2010). ...
... Carbonate formations are the most important type of hydrocarbon reservoirs (Kargarpour, 2020). Aljuboori et al. (2019) reported that 70% of conventional oil reserves in the Middle East lies in carbonate reservoirs. Commonly, in many cases, carbonate reservoirs are tight, hence, it is highly recommended to apply an efficient well stimulation, e.g., acid or hydraulic fracturing. ...
The Fuman Oilfield in Tarim Basin has great potential for ultra-deep carbonate oil and gas resources, and is an important area for future storage and production increase. The present-day in-situ stress field is critical during the exploration and development. However, no systemic investigations have been carried out in this oilfield. Therefore, in this study, the present-day in-situ stress field in the Ordovician carbonate reservoir is predicted and analyzed based on well log calculation and geomechanical numerical modeling. The results indicate that, 1) NE-SW-trending is the dominant horizontal maximum principal stress ( S Hmax ) orientation. The vertical principal stress is the maximum principal stress, showing the Ordovician reservoir is under a normal faulting stress regime. 2) The distribution of in-situ stresses in the Ordovician carbonate reservoir is heterogeneous, which is mainly controlled burial depth and fault/fracture development. High stress magnitudes in the Yingshan Formation are mainly in the southeastern part of Fudong area, Fuman Oilfield. The present-day horizontal differential stress mainly ranges from 27 MPa to 30 MPa in the Yingshan carbonate reservoir. iii) Natural fractures are generally stale under the present-day in-situ stress state. Fractures that parallel to the S Hmax orientation with high fracture dip angle are easier to be reactivated. The results are expected to provide geomechanical references for further oil and gas development in the Fuman Oilfield of Tarim Basin.
... Carbonate reservoirs are a common type of reservoir system that can produce a signi cant amount of oil and gas. The carbonate reservoirs contain approximately 50-60% of the oil and gas reserves in the world (e.g., Akbar et al. 2000; Aljuboori et al. 2019). In fact, the largest oil eld in the world (Ghawar, Saudi Arabia) and the largest gas eld in the world (North Field/South Pars) are both carbonate rock reservoirs (Garland, J. et al. 2012). ...
The key obstacles to the development of the four wells in the Pariwali Block of the Potwar Basin in Pakistan continue to be an accurate age diagnosis of the reservoir intervals, facies variation, and locating the hydrocarbon target for future development wells. The purpose of this work is to offer integrated biostratigraphic, facies, and sequence stratigraphic information from well cuttings in order to more fully characterize the carbonate reservoirs. The diagnosis of exact stratigraphic units, their ages, and order of cyclicity were constrained by larger benthic foraminiferal biostratigraphy, and the facies integration has made it possible to identify the sequence stratigraphic architecture. The Paleogene Lockhart, Sakessar, and Chorgali Formation were diagnosed, which were deposited on a ramp carbonate platform in a range of environments, including tidal flats, the inner ramp, the proximal middle ramp, and the outer ramp. The Transgressive Systems Tract and the Regressive Systems Tract, which make up a third-order cycle, were validated by the Lockhart, Sakessar, and Chorgali Formation in the Potwar-5, 2, and 7 wells. The facies correlation of the Potwar-2, 4, 5, and 7 wells shows a distinct vertical and lateral change. The occurrence of LBF wackestone-packstone facies possesses excellent reservoir rock characteristics as seen in the Potwar 2, 4, and 5 wells. The poor reservoir intervals are indicated by the lime mudstone facies and their absence in the Potwar-2, which may have contributed to optimal hydrocarbon recovery. The repetition of lime mudstone facies has caused the reservoir compartmentalization in Potwar 4 &7 wells.
... Oil recovery from carbonates can be exceptionally arduous compared to sandstone formations (Chavan et al., 2019). Due to its fractured character and oilwetting nature, carbonate reservoirs typically have low oil recovery factors (Chilingar and Yen, 1983;Aljuboori et al., 2019). ...
Carbonated smart water injection (CSWI) is a potential hybrid EOR technology under development. The process involves dissolving CO2 in smart water ripping the benefits of the synergic effect of CO2 injection and smart water. Based on the experimental laboratory data, including core flood experiments, this paper presents numerical investigations of the combined impact of dissolving carbon dioxide (CO2) in smart water (SW) on oil recovery in carbonate cores. An advanced processes reservoir simulator was utilized to build a core-scale model. Both the physics of smart water flooding as well as CO2-gas injection were captured. The generated model was validated against the coreflooding experimental data on hybrid CSWI, including cumulative oil production (cc) and oil recovery factor (%). The Corey's correlation relative permeability model was used for capturing the multiphase flow. The numerical model was used to understand the underlying recovery mechanisms and crude oil-brine-rock interactions during CSWI. The model was further utilized to perform sensitivity analysis of different parameters and to optimize the CSWI design.
Based on the numerical results, the experimental coreflooding data were accurately history-matched using the proposed model with a minimal error of 8.79% applying the PSO-based optimization method. Moreover, this history-matched model was further used for sensitivity analysis and optimization of the CSWI process. The objective functions for sensitivity analysis and optimization are based on minimizing the history-matching global error and maximizing oil recovery. The optimized design was achieved by performing a sensitivity analysis of various input parameters such as oil and water saturations (Soi and Swi), DTRAP (i.e., relative permeability interpolation parameter). On the other hand, in terms of maximizing the oil recovery while minimizing the usage of injected CSW solutions during CSWI, the optimal solution via the PSO-based approach achieved a cumulative oil recovery of 55.5%. The main mechanism behind additional oil recovery with CSW is due mainly to wettability alteration and ion exchange between rock and brine. Additionally, CSWI was found to be more efficient in releasing trapped oil compared to waterflooding, indicating the synergic effect of dissolved CO2 in SW solutions. Based on this research, the envelope of CSWI application in carbonates for CO2-storage is expected to expand. This study presents one of the few works on numerical modeling of the CSWI process and capturing its effects on oil recovery. The optimized core-scale model can be further used as a base to build a field-scale model. This promising hybrid CSWI process under optimum conditions is expected to be economical and environmentally acceptable, which promotes future field projects.
... However, extraction from carbonate reservoirs is generally more challenging than sandstone reservoirs [1]. Firstly, most of them are naturally fractured, and secondly, more than 20% of current oil production is from naturally fractured reservoirs [2]. Secondly, up to 77% are oil wet [3], rendering them less susceptible to spontaneous water imbibition. ...
Carbonated water has proven advantages over conventional CO2 injection in terms of arresting free CO2 mobility, low-pressure injection, lower volume requirement, and higher efficiency. The term “engineered water” is designated to selective ion-spiked injection water with the advantage of the ion-exchange reactions with the rock minerals and releasing trapped oil. This article investigated the synergic effect of dissolved CO2 and engineered water for oil recovery and understanding inner mechanisms. Recovery efficiencies were evaluated through coreflood studies, which revealed that the hybrid water could recover 6–10% more oil than engineered water and about 3% more than carbonated water. HP-HT pendant-drop studies show the insignificance of IFT reduction. Wettability change from oil wet to near-water wet is attributed as a significant factor. The dissolution of Ca2+ and Mg2+ and deposition of SO42− observed in coreflooding may have a significant contribution to oil recovery. Pore enlargement evidenced in NMR-PSD and NMR-ICP results support this claim. The study confirmed that the EWI-CWI hybrid technique could be a promising EOR method, eliminating the requirement for high-pressure injection, the problems of gravity segregation, and the early breakthrough of CO2. It can also be an effective EOR solution, providing a significant cost advantage and higher oil recovery in addition to the environmental benefits of CO2 sequestration.
... Fluid flow in NFRs is signified by various physical phenomena, including gravity drainage, diffusion, capillarity, and imbibition acting as the core recovery mechanisms that organize the flowing fluid between the matrix blocks and the surrounding fractures [6,7]. In an NFR with a primary or secondary gas cap, the main recovery mechanism is given by the gas-oil gravity drainage in gravityassisted processes or during natural depletion [8,9]. In this mechanism, the voidage volume is replaced with gas with gravity as the principal driving force [10]. ...
In this study, a surrogate model is developed based on single porosity modelling approach to predict the gas-oil gravity drainage recovery curves. The single porosity model is validated against experimental data associated with gravity drainage available for an actual core sample gathered from a naturally fractured reservoir. Then, using the single porosity model and a vast databank of rock and fluid data, the gravity drainage recovery curves are generated. Two empirical functions, namely Lambert and Aronofsky are then utilized to match the generated recovery curves. An exact graphical approach based on saturation profiles is put forth to compute ultimate oil recovery and an artificial neural network is developed to predict the convergence constant. The findings imply that unlike Lambert, Aronofsky is more accurate in capturing the simulation-generated recovery curves. The Lambert function overpredicts the early-time and underpredicts late-time oil recovery in most cases. The statistical parameters and plotted graphs indicate that the developed surrogate model is robust and precise in predicting the Aronofsky function convergence constant. In addition, it is found that unlike absolute permeability and maximum oil relative permeability, other parameters including block height, oil viscosity, and porosity directly correlate with the time required to reach ultimate oil recovery. The presented graphical approach indicates that initial water saturation, density difference, block height, and capillary pressure curve are the only parameters that could affect the ultimate oil recovery. The sensitivity analysis aided by the developed surrogate model and Monte Carlo algorithm affirms that absolute permeability and density difference are the parameters that have the maximum and minimum impact, respectively, on the time required to reach the ultimate recovery.
... Hydrocarbon recovery mechanisms from naturally fractured reservoirs (NFR) are considerably more complicated compared with conventional ones. However, since more than 20% of the world's oil is being produced from NFRs [3], investigation of such mechanisms has always been an attractive research topic [3][4][5][6]. ...
Many studies have been performed in the field of smart water injection and its combination with chemical methods to improve oil recovery. However, there has been less previous evidence for the efficiency of a mixture of cationic and nonionic surfactants combined with smart water for enhanced oil recovery in carbonate reservoirs. Therefore, in the current study, we aimed to investigate the effects of such a combination to enhance oil recovery from a fractured carbonate reservoir. Phase behavior experiments, IFT, and contact angle measurements were performed to design the optimal solution for EOR experiments. Then, through a series of flooding experiments, imbibition tests and simulations, and dimensionless analysis, the efficiency of the designed smart water-surfactant solution was examined. The results demonstrate a strong synergy between low salinity water and surfactant for recovering oil from carbonate reservoirs, as their optimal combination could recover up to 51.1% and 41.25% of the original oil-in-place in the core flood and imbibition experiments, respectively.
... The porosity-permeability of the matrix block was found to have the greatest effect on this phenomenon, while the height of the matrix block had the least effect. Several numerical models, at different scales, were built by Aljuboori et al. (2019) to examine gravity drainage. They also investigated the influence of parameters such as matrix block dimensions and permeability on gravity drainage rate. ...
... Table 2 shows the properties of the fluid (viscosity and density) used in the base model. It should be highlighted that all properties were chosen in the range of fractured reservoirs reported in previous works (Erfani et al., 2021;Aghabarari and Ghaedi, 2019;Aljuboori et al., 2019;Hashemi and Bashiri, 2013;Mashayekhizadeh et al., 2011;Shariat et al., 2006). ...
... In this study, the capillary pressure value in fractures was assumed zero, and straight relation between relative permeability and oil saturation was considered for the model. These assumptions were utilized in previous works as well (Aghabarari and Ghaedi, 2019;Aljuboori et al., 2019;Rahmati and Rasaei, 2019). ...
In fractured reservoirs, block-to-block interactions (re-infiltration and capillary continuity) significantly affect gravity drainage performance. Re-infiltration controls the drainage rate. This process may significantly delay oil production. Despite the numerous attempts to study the re-infiltration process, there is still much controversy about the factors that affect this phenomenon. This work focused on designing two sets of 2D models aimed at improving the simulation and visualization of multiphase flow in fractured porous media while providing a more realistic understanding of the pore-scale phenomena and flow communication between matrix-fracture and matrix-matrix. The simulation was performed in COMSOL Multiphysics in the single-porosity model. Moreover, the impact of different parameters such as rock type, physical properties of the fluids, tilt angle, matrix block height and area, fracture opening, and matrix blocks porosity-permeability on gravity drainage performance, especially block-to-block interactions, has been examined. Besides investigating the effect of each parameter, combined effects of those parameters have likewise been investigated. To rank the most critical observed parameters on the re-infiltration process, the grey relational analysis was applied. The results of this analysis showed the physical properties of the fluids have the most influence on re-infiltration. In addition, it was demonstrated that tilt angle reduces the degree of re-infiltration in deviated blocks. Also, a combination of oil-wet rocks and high irreducible water saturation results in a decrease in oil recovery, a delay in production, and a decrease in the degree of re-infiltration. Additionally, fractures with small openings and taller blocks promote greater re-infiltration; however, their impact on ultimate recovery is not significant. The findings of this study can help for a better understanding of the relative influence of different reservoir parameters on gravity drainage performance and block-to-block interactions.
... In our previous work, we presented a detailed discussion about the Qamchuqa reservoir (which includes both Upper and Lower Qamchuqa formations), besides a brief explanation about the local region (Aljuboori et al. 2019(Aljuboori et al. , 2020a. Therefore, a glimpse of Lower Qamchuqa formation has been provided in this work to highlight its characteristics. ...
Permeability is an essential parameter for the reservoir characteristics, which controls the flowing fluids in the reservoir hence the sweep efficiency and the ultimate recovery. The common practice in the petroleum industry is coring a limited number of wells, due to the expensive core recovery process, and measuring the permeability in the recovered cores then extend the concluded correlation to the un-cored wells. However, establishing a reliable permeability predictor is not an easy task in many heterogeneous formations due to the spatial variability of the permeability even at very close distances. Therefore, the conventional linear regression has often failed to address the formation’s heterogeneity, and an unsatisfied correlation coefficient has frequently obtained. Lower Qamchuqa formation, which is highly prolific producing formation in the Middle East, has been used as an example of highly heterogeneous carbonate systems. Well log measurements, which are available for most of the wells, in addition to the core data, were used to capture the high heterogeneity of the depositional environment. Core-log depth calibration was first performed to extract the accurate log measurements that correspond to the actual core data depth. Then, both core and log data were listed in a table for the statistical analysis using the neural network (NN) and multivariate regression approaches. A remarkable improvement in the correlation coefficient was obtained using the NN approach. The utilised training data and further verified by the validation data set have obtained a favourable accuracy compared with conventional linear regression or multivariate regression. The NN permeability predictor has proven its ability to overcome the complexity of the carbonate rock textures and the variety of the diagenesis alteration processes, which make the NN approach a superior method in obtaining an improved permeability predictor. Nevertheless, a regular update to estimate the permeability predictor would be necessary when new data acquired.
... Outcrop data have increasingly used and can be utilised in various modelling and simulation purposes, such as (1) to construct fractured models for reservoir simulation purposes (Aljuboori et al. 2019;Geiger and Matthäi 2012), (2) to build a structural interpretation (Lewis et al. 2007), (3) to assist in seismic interpretation to narrow the related uncertainties (Welbon et al. 2007), (4) to construct a conceptual model to predict the deformation of the rocks in different geological settings (Bergbauer 2007), (5) hydrothermal fluid activity and thermochemical sulphate reduction process in carbonates during diagenesis (Jiang et al. 2015), and (6) numerical well testing and subsurface pressure response of fractured reservoirs (Aljuboori et al. 2015). ...
... The formation consists of shallow marine thick-bedded limestone with often extensive dolomitisation (Al-Zaidy et al. 2014). Its thickness exceeds 300 m in the northern area of the field, which is the main reservoir region; further details can be found in the study (Aljuboori et al. 2019). A core data of 165.9 m, which have been taken from seven wells, were used to populate the matrix cells with porosity and permeability in the geological model. ...
... (3) New aperture = if (aperture ≤ 180, 0, aperture) Fig. 3 The sequence stratigraphy of the Qamchuqa reservoir, highlighting the producing formations in the Jambur field indicated by red dots within the foothill zone including Lower Qamchuqa formation (Aljuboori et al. 2019(Aljuboori et al. , 2020b, modified after (Jassim et al. 2006) • Conclude a simple linear regression to predict the impact of the cement percentage on the fracture permeability. ...
Naturally fractured carbonate reservoirs are often described as very heterogeneous systems due to the carbonate depositional environment and to the subsequent diagenesis processes such as mineral precipitation in fractures. Fluid flow behaviour in fractures is highly influenced by the fracture aperture size and its morphology. Mineral precipitation can alter the fracture effectiveness to the fluid flow and cause a partial or entire blockage of fractures. Therefore, accurate characterisation of the fracture morphology can help to enhance the prediction of the fluid flow behaviour in naturally fractured carbonate reservoirs. Mineral precipitation on fracture walls can reduce the fracture aperture significantly. As a result, the fracture permeability affected notably, which reduces the flow potential through fractures as well as changes the flow pattern. The objective of this work is to predict the flow behaviour in fractures under various levels of mineral precipitation to mimic reality. We have approached this objective by using outcrop-based models supported by a set of rock and fluid properties of a nearby fractured formation. Then, the model tested for the gas flow using the derivative plot technique of the synthetic well testing data. The simulation results have shown that mineral cementation can cause a partial blockage in fractures, hence a reduction in their flow capacity, as fractures become a less conductive medium. Nevertheless, the matrix medium can enhance the fluid flow in fractures by providing a bypass path to the fluid to overcome the sealed fractures. In this work, a formula has concluded to estimate the reduction in fracture permeability based on the fraction of the precipitated cement. In the studied formation, the core description has shown that 34% of fractures were blocked, which can lead to a reduction in the permeability by 29–64% and by 37–83% with and without matrix contribution, respectively. Thus, including the fracture morphology in the simulation model enables us to predict the performance of fractured carbonate reservoirs accurately.
