Characterization of Matrix Wettability and Mass Transfer From Matrix to Fractures in Carbonate Reservoirs

2012 ◽  
Author(s):  
Anuj Gupta
Keyword(s):  
Oil Recovery ◽  
History Matching ◽  
Oil And Gas ◽  
Fractured Reservoirs ◽  
Naturally Fractured Reservoirs ◽  
Carbonate Reservoirs ◽  
Shape Factors ◽  
Naturally Fractured ◽  
Fractured Carbonate ◽  
The Matrix

This paper presents results of an experimental investigation, supported by numerical analysis, to characterize oil recovery from fractured carbonate reservoirs. Imbibition recovery of oil is measured as a function of time for samples with varying wettability and shape factors. One of the objectives of this study is to verify the validity of exponential transfer function for matrix-fracture systems with varying wettability and flow-boundary conditions. Another objective is to establish the possibility of quantitatively determining the wettability of a sample based on history-matching of cumulative imbibition recovery and recovery rate data. The productivity of most carbonate oil and gas reservoirs is closely tied to the natural or stimulated fracture system present in the reservoir. Further, the recovery from naturally fractured reservoirs, in presence of aquifer drive or waterflooding is closely tied to the wettability of the matrix. The approach presented in this paper offers means to evaluate how recovery factor in a fractured system can be affected by wettability. A detailed understanding of rock-fluid interactions and wettability alterations at the fracturing face should help design improved strategies for exploiting naturally fractured carbonate reservoirs.

scholarly journals Gravity Drainage Mechanism in Naturally Fractured Carbonate Reservoirs; Review and Application

Energies ◽  
2019 ◽  
Vol 12 (19) ◽  
pp. 3699 ◽  
Author(s):  
Faisal Awad Aljuboori ◽  
Jang Hyun Lee ◽  
Khaled A. Elraies ◽  
Karl D. Stephen
Keyword(s):  
Gravity Model ◽  
Oil Recovery ◽  
Fractured Reservoirs ◽  
Carbonate Reservoir ◽  
Real Field ◽  
Gravity Drainage ◽  
Naturally Fractured ◽  
Fractured Carbonate ◽  
Matrix Blocks ◽  
The Matrix

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, understanding each mathematical model can help in deciding the best gravity model that suits each reservoir case. Real field data from a naturally fractured carbonate reservoir from the Middle East have used to examine the performance of various gravity equations. The reservoir represents a gas–oil system and has four decades of production history, which provided the required mean to evaluate the performance of each gravity model. The simulation outcomes demonstrated remarkable differences in the oil and gas saturation profile and in the oil recovery speed from the matrix blocks, which attributed to a different definition of the flow potential in the vertical direction. Moreover, a sensitivity study showed that some matrix parameters such as block height and vertical permeability exhibited a different behavior and effectiveness in each gravity model, which highlighted the associated uncertainty to the possible range that often used in the simulation. These parameters should be modelled accurately to avoid overestimation of the oil recovery from the matrix blocks, recovery speed, and to capture the advanced gas front in the oil zone.

An Experimental Study of Wetting Behavior and Surfactant EOR in Carbonates With Model Compounds

SPE Journal ◽  
2008 ◽  
Vol 13 (01) ◽  
pp. 26-34 ◽  
Author(s):  
Yongfu Wu ◽  
Patrick J. Shuler ◽  
Mario Blanco ◽  
Yongchun Tang ◽  
William A. Goddard
Keyword(s):  
Oil Recovery ◽  
Anionic Surfactants ◽  
Fractured Reservoirs ◽  
Naphthenic Acids ◽  
Carbonate Reservoirs ◽  
Reservoir Rock ◽  
Intermediate Water ◽  
Wetting Behavior ◽  
Fractured Carbonate ◽  
The Matrix

Summary This study focuses on the mechanisms responsible for enhanced oil recovery (EOR) from fractured carbonate reservoirs by surfactant solutions, and methods to screen for effective chemical formulations quickly. One key to this EOR process is the surfactant solution reversing the wettability of the carbonate surfaces from less water-wet to more water-wet conditions. This effect allows the aqueous phase to imbibe into the matrix spontaneously and expel oil bypassed by a waterflood. This study used different naphthenic acids (NA) dissolved in decane as a model oil to render calcite surfaces less water-wet. Because pure compounds are used, trends in wetting behavior can be related to NA molecular structure as measured by solid adsorption; contact angle; and a novel, simple flotation test with calcite powder. Experiments with different surfactants and NA-treated calcite powder provide information about mechanisms responsible for sought-after reversal to a more water-wet state. Results indicate this flotation test is a useful rapid screening tool to identify better EOR surfactants for carbonates. The study considers the application of surfactants for EOR from carbonate reservoirs. This technology provides a new opportunity for EOR, especially for fractured carbonate, where waterflood response typically is poor and the matrix is a high oil-saturation target. Introduction Typically only approximately a third of the original oil in place (OOIP) is recovered by primary and secondary recovery processes, leaving two-thirds trapped in reservoirs as residual oil. Approximately half of world's discovered oil reserves are in carbonate reservoirs and many of these reservoirs are naturally fractured (Roehl and Choquette 1985). According to a recent review of 100 fractured reservoirs (Allan and Sun 2003), carbonate fractured reservoirs with high matrix porosity and low matrix permeability especially could use EOR processes. The oil recovery from these reservoirs is typically very low by conventional waterflooding, due in part to fractured carbonate reservoirs (about 80%) being originally less water-wet. Injected water will not penetrate easily into a less water-wetting porous matrix and so cannot displace that oil in place. Wettability of carbonate reservoirs has been widely recognized an important parameter in oil recovery by flooding technology (Tong et al. 2002; Morrow and Mason 2001; Zhou et al. 2000; Hirasaki and Zhang 2004). Because altering the wettability of a rock surface to preferentially more water-wet conditions is critical to oil recovery, alteration of reservoir wettability by surfactants has been intensively studied, and many research papers have been published (Spinler and Baldwin 2000). Vijapurapu and Rao (2004) studied the capability of certain ethoxy alcohol surfactants to alter wettability of the Yates reservoir rock to water-wet conditions. Seethepali et al. (2004) reported that several anionic surfactants in the presence of Na2CO3 can change a calcite surface wetted by a West Texas crude oil to intermediate/water-wet conditions as well as, or even better than, an efficient cationic surfactant. Zhang et al. (2004) investigated also the effect of electrolyte concentration, surfactant concentration, and water/oil ratio on wettability alteration. They reported that wettability of calcite surface can be altered to approximately intermediate water-wet to preferentially water-wet conditions with alkaline/anionic surfactant systems. Adsorption of anionic surfactants on a dolomite surface can be significantly reduced in the presence of sodium carbonate.

Comparison of Chemical-Component Transport in Naturally Fractured Reservoirs Using Dual-Porosity and Multiple-Interacting-Continua Models

SPE Journal ◽  
2020 ◽  
Vol 25 (04) ◽  
pp. 1964-1980
Author(s):  
Ali Al-Rudaini ◽  
Sebastian Geiger ◽  
Eric Mackay ◽  
Christine Maier ◽  
Jackson Pola
Keyword(s):  
Oil Recovery ◽  
Fractured Reservoirs ◽  
Transport Processes ◽  
Chemical Component ◽  
Naturally Fractured Reservoirs ◽  
Spontaneous Imbibition ◽  
Dual Porosity ◽  
Fine Scale ◽  
Naturally Fractured ◽  
The Matrix

Summary We propose a workflow to optimize the configuration of multiple-interacting-continua (MINC) models and overcome the limitations of the classical dual-porosity (DP) model when simulating chemical-component-transport processes during two-phase flow. Our new approach captures the evolution of the saturation and concentration fronts inside the matrix, which is key to design more effective chemical enhanced-oil-recovery (CEOR) projects in naturally fractured reservoirs. Our workflow is intuitive and derived from the simple concept that fine-scale single-porosity (SP) models capture fracture/matrix interaction accurately; it can hence be easily applied in any reservoir simulator with MINC capabilities. Results from the fine-scale SP model are translated into an equivalent MINC model that yields more accurate results compared with a classical DP model for oil recovery by spontaneous imbibition; for example, in a water-wet (WW) case, the root-mean-square error (RMSE) improves from 0.123 to 0.034. In general, improved simulation results can be obtained when selecting five or fewer shells in the MINC model. However, the actual number of shells is case specific. The largest improvement in accuracy is observed for cases where the matrix permeability is low and fracture/matrix transfer remains in a transient state for a prolonged time. The novelty of our approach is the simplicity of defining shells for a MINC model such that the chemical-component-transport process in naturally fractured reservoirs can be predicted more accurately, especially in cases where the matrix has low permeability. Hence, the improved MINC model is particularly suitable to model chemical-component transport, key to many CEOR processes, in (tight) fractured carbonates.

Effect of DFN Upscaling on History Matching and Prediction of Naturally Fractured Reservoirs

2013 ◽  
Author(s):  
Mohamed Ahmed Elfeel ◽  
Sarim Jamal ◽  
Chukwuemeka Enemanna ◽  
Dan Arnold ◽  
Sebastian Geiger
Keyword(s):  
History Matching ◽  
Fractured Reservoirs ◽  
Naturally Fractured Reservoirs ◽  
Naturally Fractured

Pressure-Transient Tests and Flow Regimes in Fractured Reservoirs

2015 ◽  
Vol 18 (02) ◽  
pp. 187-204 ◽  
Author(s):  
Fikri Kuchuk ◽  
Denis Biryukov
Keyword(s):  
History Matching ◽  
Fractured Reservoirs ◽  
Flow Regimes ◽  
Naturally Fractured Reservoirs ◽  
Dual Porosity ◽  
Hydraulic Fractures ◽  
Fractured Reservoir ◽  
Pressure Transient ◽  
Matrix Block ◽  
Naturally Fractured

Summary Fractures are common features in many well-known reservoirs. Naturally fractured reservoirs include fractured igneous, metamorphic, and sedimentary rocks (matrix). Faults in many naturally fractured carbonate reservoirs often have high-permeability zones, and are connected to numerous fractures that have varying conductivities. Furthermore, in many naturally fractured reservoirs, faults and fractures can be discrete (rather than connected-network dual-porosity systems). In this paper, we investigate the pressure-transient behavior of continuously and discretely naturally fractured reservoirs with semianalytical solutions. These fractured reservoirs can contain periodically or arbitrarily distributed finite- and/or infinite-conductivity fractures with different lengths and orientations. Unlike the single-derivative shape of the Warren and Root (1963) model, fractured reservoirs exhibit diverse pressure behaviors as well as more than 10 flow regimes. There are seven important factors that dominate the pressure-transient test as well as flow-regime behaviors of fractured reservoirs: (1) fractures intersect the wellbore parallel to its axis, with a dipping angle of 90° (vertical fractures), including hydraulic fractures; (2) fractures intersect the wellbore with dipping angles from 0° to less than 90°; (3) fractures are in the vicinity of the wellbore; (4) fractures have extremely high or low fracture and fault conductivities; (5) fractures have various sizes and distributions; (6) fractures have high and low matrix block permeabilities; and (7) fractures are damaged (skin zone) as a result of drilling and completion operations and fluids. All flow regimes associated with these factors are shown for a number of continuously and discretely fractured reservoirs with different well and fracture configurations. For a few cases, these flow regimes were compared with those from the field data. We performed history matching of the pressure-transient data generated from our discretely and continuously fractured reservoir models with the Warren and Root (1963) dual-porosity-type models, and it is shown that they yield incorrect reservoir parameters.

Low-IFT Foaming System for Enhanced Oil Recovery in Highly Heterogeneous/Fractured Oil-Wet Carbonate Reservoirs

SPE Journal ◽  
2018 ◽  
Vol 23 (06) ◽  
pp. 2243-2259 ◽  
Author(s):  
Pengfei Dong ◽  
Maura Puerto ◽  
Guoqing Jian ◽  
Kun Ma ◽  
Khalid Mateen ◽  
...  
Keyword(s):  
Oil Recovery ◽  
Fractured Reservoirs ◽  
Surfactant Solution ◽  
Capillary Forces ◽  
Mobility Control ◽  
Carbonate Reservoirs ◽  
Residual Oil ◽  
High Permeability ◽  
The Matrix ◽  
Foam Flooding

Summary Oil recovery in heterogeneous carbonate reservoirs is typically inefficient because of the presence of high-permeability fracture networks and unfavorable capillary forces within the oil-wet matrix. Foam, as a mobility-control agent, has been proposed to mitigate the effect of reservoir heterogeneity by diverting injected fluids from the high-permeability fractured zones into the low-permeability unswept rock matrix, hence improving the sweep efficiency. This paper describes the use of a low-interfacial-tension (low-IFT) foaming formulation to improve oil recovery in highly heterogeneous/fractured oil-wet carbonate reservoirs. This formulation provides both mobility control and oil/water IFT reduction to overcome the unfavorable capillary forces preventing invading fluids from entering an oil-filled matrix. Thus, as expected, the combination of mobility control and low-IFT significantly improves oil recovery compared with either foam or surfactant flooding. A three-component surfactant formulation was tailored using phase-behavior tests with seawater and crude oil from a targeted reservoir. The optimized formulation simultaneously can generate IFT of 10−2 mN/m and strong foam in porous media when oil is present. Foam flooding was investigated in a representative fractured core system, in which a well-defined fracture was created by splitting the core lengthwise and precisely controlling the fracture aperture by applying a specific confining pressure. The foam-flooding experiments reveal that, in an oil-wet fractured Edward Brown dolomite, our low-IFT foaming formulation recovers approximately 72% original oil in place (OOIP), whereas waterflooding recovers only less than 2% OOIP; moreover, the residual oil saturation in the matrix was lowered by more than 20% compared with a foaming formulation lacking a low-IFT property. Coreflood results also indicate that the low-IFT foam diverts primarily the aqueous surfactant solution into the matrix because of (1) mobility reduction caused by foam in the fracture, (2) significantly lower capillary entry pressure for surfactant solution compared with gas, and (3) increasing the water relative permeability in the matrix by decreasing the residual oil. The selective diversion effect of this low-IFT foaming system effectively recovers the trapped oil, which cannot be recovered with single surfactant or high-IFT foaming formulations applied to highly heterogeneous or fractured reservoirs.

scholarly journals Evaluation of an uncertainty reduction methodology based on Iterative Sensitivity Analysis (ISA) applied to naturally fractured reservoirs

2019 ◽  
Vol 74 ◽  
pp. 40 ◽  
Author(s):  
Luís Augusto Nagasaki Costa ◽  
Célio Maschio ◽  
Denis José Schiozer
Keyword(s):  
Sensitivity Analysis ◽  
History Matching ◽  
Flow Behavior ◽  
Fractured Reservoirs ◽  
Search Space ◽  
Naturally Fractured Reservoirs ◽  
Reservoir Modeling ◽  
Naturally Fractured ◽  
Geostatistical Techniques

History matching for naturally fractured reservoirs is challenging because of the complexity of flow behavior in the fracture-matrix combination. Calibrating these models in a history-matching procedure normally requires integration with geostatistical techniques (Big Loop, where the history matching is integrated to reservoir modeling) for proper model characterization. In problems involving complex reservoir models, it is common to apply techniques such as sensitivity analysis to evaluate and identify most influential attributes to focus the efforts on what most impact the response. Conventional Sensitivity Analysis (CSA), in which a subset of attributes is fixed at a unique value, may over-reduce the search space so that it might not be properly explored. An alternative is an Iterative Sensitivity Analysis (ISA), in which CSA is applied multiple times throughout the iterations. ISA follows three main steps: (a) CSA identifies Group i of influential attributes (i = 1, 2, 3, …, n); (b) reduce uncertainty of Group i, with other attributes with fixed values; and (c) return to step (a) and repeat the process. Conducting CSA multiple times allows the identification of influential attributes hidden by the high uncertainty of the most influential attributes. In this work, we assess three methods: Method 1 – ISA, Method 2 – CSA, and Method 3 – without sensitivity analysis, i.e., varying all uncertain attributes (larger searching space). Results showed that the number of simulation runs for Method 1 dropped 24% compared to Method 3 and 12% to Method 2 to reach a similar matching quality of acceptable models. In other words, Method 1 reached a similar quality of results with fewer simulations. Therefore, ISA can perform as good as CSA demanding fewer simulations. All three methods identified the same five most influential attributes of the initial 18. Even with many uncertain attributes, only a small percentage is responsible for most of the variability of responses. Also, their identification is essential for efficient history matching. For the case presented in this work, few fracture attributes were responsible for most of the variability of the responses.

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