Naturally Fractured Reservoirs Research Articles

Mechanistic analysis of acid gas storage and oil recovery in naturally fractured reservoirs using single matrix block approach

AbstractThe objective of this study is to assess the storage of acid gas, containing CO2 and H2S, in a depleted naturally fractured reservoir (NFR) using single matrix block (SMB) approach. The acid gas dissolution in oil is considered by Peng‐Robinson equation of state and compositional simulation. The PHREEQC package is used to determine acid gas solubility in formation brine. Three types of acid gases with different compositions are used for this study and their swelling behavior and miscibility in relation to the reservoir oil are analyzed. An SMB model, with a matrix block surrounded by fractures, is constructed, and validated for simulation of a real experiment. The simulation is conducted for synthetic and real reservoir fluids when the oil is in its residual saturation. A sensitivity analysis is performed to study the effects of key parameters, such as acid gas composition, reservoir pressure, permeability, porosity and matrix height on the storage capacity and oil recovery factor. The matrix has a volume of 27 m3 and about half of acid gas storage is achieved in the first 5 years while the simulations are run for 30 years. The results show that up to 90% of remained oil is recoverable, and more than 0.67 kmol of acid gas per cubic meter of matrix is stored whether matrix contains a real oil or a synthetic one. Higher storage is achieved for higher matrix porosities and heights and large H2S proportion in acid gas. In all cases about 10% of acid gas is trapped in water and the remaining 90% is dissolved in oil. The mineral trapping was more active in CO2‐rich acid gases. While about 10 kg of the matrix rock was dissolved in the acidic brine when the acid gas contained H2S, the amount of the dissolved minerals in acidic brine resulted from the injection of CO2‐rich acid gas was more than 16 kg. Finally, this study gives a comparative analysis of the storage performance of acid gas mixture and pure CO2. © 2024 Society of Chemical Industry and John Wiley & Sons, Ltd.

Unlocking the enormous potential of biological materials: Polymer-assisted foam for enhanced oil recovery in fractured porous media

In natural fractured reservoirs, foam serves as an effective method for mobility control, leading to a significant enhancement in oil recovery. However, the harsh conditions of reservoirs present challenges to the strength and stability of foams. In this study, we conducted comprehensive experimental research, employing a combination and screening approach, to successfully develop a super foam using biomacromolecules (Welan gum) and bio-based surfactants (APG). Bulk foam tests were carried out and the performance of foam flooding in fractured porous media was evaluated. The results demonstrated that the introduction of Welan gum significantly increased the strength of the foam and improved its rheological properties. The Welan gum-enhanced foam (WG-foam) exhibited higher flow resistance in fractured reservoirs, resulting in enhanced oil recovery. Compared to traditional hydrophobically associating polymer-enhanced foam (HAPAM-foam), the WG-foam showed a remarkable half-life for drainage of 20 h, which is 13 times longer than that of HAPAM-foam. Furthermore, the ultimate oil recovery of WG-foam was 21% higher than that of HAPAM, reaching 87%. Through molecular dynamics simulations, we uncovered the exceptional water-binding capacity of Welan gum, which significantly delayed the drainage rate in the foam lamella, thus enhancing foam stability. This work not only provides a powerful technical approach for foam-enhanced oil recovery, but also offers new insights into the fabrication of high-performance foams.

The Dependence of Water and Gas Breakthrough on the Choice of Model Parameters in Naturally Fractured Reservoirs Using Sector and Full Reservoir Models

Assessing fractures in carbonate reservoirs is crucial due to their substantial impact on reservoir permeability. Understanding the characteristics of these fractures is vital for optimizing oil production. Additionally, extremely heterogeneous and anisotropic permeability distribution within the natural fractured reservoir is often caused by the complexity of a fracture network. Therefore, accurate reservoir modelling and simulation must be conducted in order to achieve ultimate recovery. In this paper, a sector model has been developed based on the studied example field, and its results are compared with the full reservoir model to find out the degree of resemblance between their outputs. The study area has four natural fracture compartments, with an average reservoir height of 95m and WOC and GOC depths of 685 m and 590 m, respectively. A dual-porosity and single-permeability modelling system was used to simulate the properties of the reservoir rock. This model was derived from the Petrel layercake model. A sensitivity analysis was also carried out to look into the relationships between field performance and the well. The outcomes of both models demonstrated that matrix permeability and fracture dimension had a significant impact on the early breakthrough of water and gas to comparable, huge extents. Other factors, such as aquifer size and WOC, show a moderate impact on water and gas breakthrough as well as final recovery.

Characterization of a naturally fractured ignimbrite reservoir: Subsurface model validated from worldwide analogue outcrops and production data

Ignimbrites are deposits found in sedimentary basins globally, commonly linked with evolved volcanism. Understanding fractured ignimbrites in sedimentary basins is crucial for various economic applications, including hydrocarbon extraction, CO2 storage, fractured aquifers, and geothermal resources. Fractured ignimbrite reservoirs typically consist of welded deposits with high transmissibility due to the fracture network, but with low matrix permeability. In this study, we demonstrate how a large-scale rhyolite eruption progressed through varying gas-particle ratios and magma discharge rates, which along with the influence of paleotopography, controlled the type and rate of deposition of pyroclastic density currents (PDCs). These factors determined the distribution and thickness of the ignimbrite unit, as well as the post-emplacement processes, such as cooling rate, welding and devitrification, which influenced the occurrence of discrete discontinuities defining the hydraulic system of the Naturally Fractured Reservoir (NFR). Fracture network is closely related to the cooling stage, composed of hybrid, fluid-assisted fractures and extensional fractures associated with fumarolic system and tensional thermo-elastic geomechanics, respectively. The subsurface model was validated through analysis of reservoir dynamic response and comparative studies of worldwide outcrop analogues, focusing on the determining factors of NFRs. In this case, tectonic fractures resulting from the structural evolution of basins may also influence reservoir conditions, albeit to a lesser extent, affecting fracture porosity and permeability of the NFR. However, these tectonic fractures played a significant role in fluid migration and reservoir charging. We conclude that an ignimbrite geobody, with a low porosity and permeability matrix (Øm ∼1 %; Km ∼0.1 mD), constitutes a NFR, where the fracture network provides a low porosity (Øf ∼0.08%) and a high anisotropic permeability of the reservoir (Kf max ∼ 2100 mD and, Kf Av ∼1500 mD). The obtained results have important implications for the study of fluids transmissibility and storage of ignimbrite reservoirs.

Automatic characterization and quantitative analysis of seismic facies in naturally fractured reservoir: Case study of Amguid Messaoud field, Algeria

Purpose. Natural fractured reservoirs are a special category of reservoirs due to the effects of porosity and permeability. Optimizing the exploitation of hydrocarbon reserves in this type of reservoir requires a specific study compared to other conventional reservoirs. Methods. We have focused on the quantitative analysis of seismic traces for the purpose of an automatic seismic facies recognition strategy. The study area, the Amguid-Messaoud Basin, is formed by a series of horsts and grabens bounded by submeridional “North-East and South-West” faults, as well as perpendicular “North-West and South-East” faults with-out outcrops of fractures, which have a great influence on reservoir fracturing. A set of statistical data analysis methods, such as principal component analysis, discriminant factor analysis, and automatic classification, have been tested on real data from geophysical seismic data interpretation, in particular the stratigraphic interpretation. Findings. The results obtained show a better use of data, which, however, are of a different nature, leading to a reliable interpretation of the geological environment. Originality. The methodology proved to be useful for constructing a reservoir model and predicting the geological properties of the reservoir along a field. Practical implications. The results obtained clearly demonstrate the best use of data, which, however, are of a different nature, which leads to a reliable interpretation of the geological environment. These methods have proved to be very useful for constructing a reservoir model and predicting the geological properties of the latter along a field.

Radius of investigation and impact of inter-porosity flow in naturally-fractured reservoirs

The radius of investigation (ROI) is an essential parameter in many reservoir engineering applications. Inconsistencies and ambiguities still exist between different ROI evaluation methods, especially for the dual-porosity (DP) system representing naturally fractured reservoirs. This paper revisited the impact of inter-porosity flow in the DP system and presented ROI equations in the early and late flow periods based on the Laplace space solution of the Warren-Root dual-porosity model. A new comprehensive ROI expression for the DP system is derived which accounts for both storativity ratio () and inter-porosity flow coefficient (). The new method in this paper reveals that the log-log plot of ROI vs. time for DP models exhibits two parallel straight lines linked by a smooth transition curve. The distance of these two straight lines is dependent on and ROI in the intermediate flow period is highly dependent on the value of The new ROI equation for the DP system can degenerate to similar ROI formula for the single-porosity system in early and late flow periods. Comparison analysis of the new method with other approaches is conducted and the validation of the new method is realized by analytical and numerical matching.

Qualitative Analysis of Drilling Fluid Loss Through Naturally-Fractured Reservoirs

Summary Drilling becomes extremely challenging when dealing with naturally fractured reservoirs (NFR). A comprehensive solution is developed in this study to perform qualitative analysis on drilling fluid loss rate and volume to examine how they can be affected by NFR characteristics, drilling fluid rheology, leakoff phenomenon, and wellbore condition. In this regard, the solution is applied to generate type curves to facilitate the sensitivity analysis (refer to the provided Supplementary Materials). The presented solution accounts for not only drilling fluid pseudoplasticity in the total system but also matrix medium under wellbore constant pressure assumption (by including dimensionless matrix contribution parameter). It is also able to measure mud loss advancement not only through NFR but also through homogeneous reservoirs. The developed solution is validated by reducing it to the preexisting solution (designed for Newtonian fluid case) by incorporating assumptions into it. The result demonstrates the significance of NFR properties and drilling fluid pseudoplasticity on the leakoff phenomenon and total loss volume, especially when constant pressure is established inside the wellbore. The finding reveals that three periods can be identified through generated type curves depending on NFR characteristics, drilling fluid rheology, and leakoff coefficient. Therefore, different drilling fluids with specific pseudoplasticity should be used in each period to mitigate drilling fluid loss effectively. In this regard, the study is supposed to design drilling fluid in a way to maintain its pseudoplasticity at a higher level at early and late times, while being maintained at a lower level during the transient period, a critical aspect for managed pressure drilling techniques, particularly in the context of dual-gradient drilling applications. Additionally, a procedure should be implemented to lessen the transient period while attempting to keep drilling fluid advancement occurrence at a lower rate, which shows that drilling fluid pseudoplasticity can be used as an effective tool to manage this period. The obtained result also indicates that the importance of drilling fluid rheology to control total loss volume is greater for NFR with higher leakoff than with lower leakoff. Furthermore, the greater the differential pressure inside the wellbore, the greater the importance of mud rheology to reduce drilling fluid loss. The outcome of the study not only facilitated qualitative and quantitative analyses through NFR but also enabled decision-makers to instantaneously select optimal wellbore conditions and drilling fluid pseudoplasticity.

A Review of Wettability Alteration by Spontaneous Imbibition Using Low-Salinity Water in Naturally Fractured Reservoirs

Analysis of fluid flow in naturally fractured reservoirs (NFRs), as a highly heterogeneous and complex system, requires a detailed study of the fracture-matrix interactions. The main process of fluid movement between the fracture and matrix is spontaneous imbibition (SI), which can occur in co/countercurrent fluid flow states. In addition, most carbonate rocks are fractured and non-water-wet, which can lead to low oil recovery. Wettability greatly affects the performance of the SI process. Injection of water or chemicals can be insufficient because fluids mostly pass through highly permeable fractures and lead to early breakthrough. Therefore, the wettability alteration mechanism should be applied in NFRs, and low-salinity water (LSW) injection is considered an effective enhanced oil recovery (EOR) approach. In this review, experimental and numerical studies of co/counter-imbibition are analyzed to show the importance of investigating the fracture-matrix interactions. In addition, the review shows the wettability effect on imbibition in fractured rocks. The review of experimental studies of LSW imbibition in fractured carbonates shows the possibilities for implementing an EOR method. However, the wettability alteration process during SI using LSW has not yet been studied, and no simulation models of co/countercurrent flows have yet been provided. Based on this review, more experimental studies are recommended to duplicate co/countercurrent imbibition using LSW. Advanced techniques such as CT scanning, MRI, and NTI can be used to reveal fluid distribution. Using experimental data, numerical models can be developed to characterize dynamic wettability alteration during co/countercurrent imbibition.

Fracture stability analysis during injection in one of the NFRs (naturally fractured reservoir) of the SW Iranian giant oil field

Fracture stability analysis during injection in one of the NFRs (naturally fractured reservoir) of the SW Iranian giant oil field

Improvement to Gravity Drainage Recovery by Repressurization as a Criterion to Screen and Rank Naturally Fractured Reservoirs for Gas Injection

Summary Many of the naturally fractured carbonate reservoirs of the Middle East exhibit low natural-depletion recoveries. The reason is that most of their oil reserves are stored in the low-permeability host rocks and are left behind by the fast advancing gas/oil contact (GOC) and water/oil contact (WOC) in fractures. Producing the remaining oil in the large gas-invaded zone of these reservoirs has been a crucial reservoir management issue. We show in this study using experimental observations, analytical calculations, and numerical investigations that repressurizing naturally fractured reservoirs (NFRs) by crestal immiscible gas injection has the potential to produce a large portion of this remaining oil by improving gravity drainage (GD) through two main mechanisms. One is that at higher pressures, the gas-oil interfacial tension (IFT) and hence the capillary forces that control recovery by GD are lessened, allowing additional recovery. This mechanism is aided by the other one, which is swelling of the oil at higher pressures. In this way, repressurization is thought to be not only a means for pressure maintenance but also a methodology for enhanced-oil recovery (EOR). This is confirmed by both laboratory studies and field performance of large-scale gas injection projects. Despite the desire for implementation of projects of repressurization, gas availability and cost of these projects are important concerns, requiring a cost-benefit analysis. Screening and ranking methodologies have been previously presented for some EOR techniques but not for repressurization by gas in NFRs. Evaluating the performance of gas injection in NFRs is often done using methodologies such as numerical simulations, which are in-depth, costly, and tedious. The methodology developed here is simple, requiring spreadsheet calculations. To develop the methodology, we first obtain simple relations to calculate additional GD recovery by considering the interplay of capillary and gravity forces in a matrix block subjected to pressurization by equilibrium gas injection and then use experimental data from literature to show that these relations can predict primary and secondary GD recoveries to a good approximation. We also show by mechanistic studies using a history-matched numerical model that IFT reduction and oil swelling are the main mechanisms contributing to additional oil recovery. Then, we propose a methodology to screen and rank candidate NFRs for gas injection that uses commonly available reservoir data and is based upon two criteria, these being additional oil recovered from a matrix block by pressurization and required volume of gas to produce an additional barrel of oil. We then implement this methodology to more than 20 Iranian NFRs and identify six reservoirs with potential for additional recovery of more than 20%. By quantifying and including the uncertainties associated with the reservoir data, we illustrate that for the reservoirs under study, capillary pressure parameters along with matrix-block height are the main parameters affecting GD recovery and should be characterized more accurately.

Underground hydrogen storage in a naturally fractured gas reservoir: The role of fracture

As hydrogen provides a high heating value with the least environmental impact, it can be considered as an energy carrier pioneer in following the global zero-carbon policies. Then, since storing hydrogen in large quantities can also be a valuable technique for alleviating energy shortages due to energy consumption fluctuations, underground hydrogen storage (UHS) is being explored further in today's world. To the best of our knowledge, the role of fracture on underground hydrogen storage performance has not comprehensively been evaluated. For the first time, in this study, the effects of fracture on hydrogen storage and production were investigated in a naturally fractured gas reservoir in the Middle East using a numerical simulation. Then, to determine whether the fracture was able to accelerate hydrogen production, UHS was evaluated under various conditions, including the fracture system, condensate presence, Initial hydrogen injection stage, cushion gas type, hydrogen storage commence time and different injection/production cycle duration. The results of this study proves that although a huge amount of hydrogen is invaded into the matrix during hydrogen injection, the fracture accelerates hydrogen production, resulting in higher hydrogen recovery and purity, which indicates fractures are suitable media for hydrogen storage. However, it should be noted that the purity of hydrogen produced from naturally fractured reservoirs (NFR) decreases more rapidly than a conventional one during a single cycle due to the higher mixing of gases in the fracture. In the case of the initial stage of hydrogen injection, fractures are not found to be attractive as storage media. Therefore, it is necessary to analyze the fracture effects as a storage media under various situations and stages. In addition, alternative gas injection revealed that nitrogen injection into cushion gas resulted in the highest hydrogen production in the entire porous media, whereas methane injection led to the highest hydrogen recovery in the fracture media. Also, the rapid injection/production cycle duration improved hydrogen recovery, indicating that the required time for high hydrogen invasion into the matrix is not provided during hydrogen injection.

Effect of gas type on miscible enhanced oil recovery at naturally fractured reservoirs: case study-Asmari

In this study, we investigate how miscibility develops in naturally fractured reservoirs. We select and simulate compositionally a sector model of a real and highly naturally fractured reservoir of type 2, and the behavior of the reservoir under the influence of different gases injection, including methane, carbon dioxide, lean and rich gas investigated. The minimum miscibility pressure of each gas and the optimum gas injection rate is determined. The effect of injected gas type on solution gas–oil ratio, surface tension, and viscosity of reservoir fluid studied. Results of this study show that the oil recovery factor in the simulation sector model over 25 years of simulation for the natural depletion scenario is 15.2% while for the miscible gas injection at the optimum injection rate is 16.7, 18.8, 17.46, and 19.4% for methane, carbon dioxide, lean gas, and rich gas respectively. Also, an improvement in the development of miscibility in the case of rich gas injection at this type of natural fractured reservoirs observed.Article HighlightsTo reach the highest RF, Gas Injection rate optimization is necessary at this type of NFRs.Injection of methane and lean gas at higher rates causes faster gas breakthrough and leads to lower ultimately oil.The rich gas shows better miscibility condition than other gases at this type of NFRs.

Pressure Transient Behaviors of Discretely Fractured Reservoirs Using a Numerical Discrete Fracture Model

Summary The conventional dual-porosity model (Warren and Root 1963) may not apply to naturally fractured reservoirs (NFRs), which have poorly connected fractures. To narrow this gap, a new discrete fracture model (DFM)-based numerical well-testing model is developed for pressure transient analysis in vertical wells interacting with natural fractures (NFs). The numerical model is based on a DFM and unstructured perpendicular bisector (PEBI) grid system. The accuracy and practicality of the proposed model have been demonstrated by model verifications with a commercial numerical software. The results show that the flow regimes of the vertical well interacting with NFs can be divided into wellbore storage and skin effects, bilinear flow, linear flow, radial flow, NF effect, and boundary-dominated flow. This is the radial flow of the formation before pressure propagates to NFs, which is virtually quite different from that in the conventional dual-porosity model. However, there are no bilinear and linear flow stages in the vertical well interacting with no NFs. It is found that the vertical well interacting with NFs has a lower pressure depletion. It is also found that the “V-shape” caused by the NF effect in the pressure derivative curve becomes deeper when there are more NFs, longer NFs, and higher fracture conductivity. Furthermore, the “V-shape” appears earlier, and the duration of the NF effect is longer as the number of NFs increases. Besides, with the decrease of the distance between the fracture and the well, the impacts of NFs on pressure transient behaviors of the vertical well are more significant. This work provides a meaningful way to understand the pressure transient behaviors of discrete NFs.

Well Placement Optimization for Fractured Reservoirs: Coupling StoSAG and EDFM

Well placement optimization is a significant task in oil field development which aims to find the optimal well locations by maximizing the net present value (NPV) or other objective function. It is a highly nonlinear problem involving large number of variables. Despite lots of work has been done on conventional reservoirs, the optimization tool for naturally fractured reservoir (NFR) is still rare. Naturally fractured reservoirs represent significant amounts of oil reserves. The well placement optimization for NFR is challenging due to the high heterogeneity of matrix and fracture system. In this work, a computer-aided well placement optimization method is established for NFR based on the recent advances. The two phases flow discrete fracture numerical simulation model, i.e., the embedded discrete fracture method (EDFM) is used to model the natural fractures as its computational efficiency and flexibility to handle fracture. Then, stochastic simplex approximate gradient (StoSAG) is employed to obtain the approximate gradient by combing the EDFM. The steepest ascent algorithm is used to find the optimal well placement. A series of numerical case studies are set up to examine the performance of the proposed approach. The NPV for water flooding naturally fractured reservoir production optimization substantially increased by using StoSAG.

Computational fluid dynamic simulation of multi-phase flow in fractured porous media during water-alternating-gas injection process

Naturally fractured reservoirs (NFRs) are among major oil and gas producing reservoirs that are commonly targeted for various enhanced oil recovery (EOR) techniques, particularly water-alternating-gas (WAG) injection. Production from NFRs is complicated due to the flow communication between the matrix and fractures in such porous media. The implementation of WAG injection in NFRs features inherent complexities not only related to the three-phase flow, saturation history, and cycle-dependent hysteresis of the individual phases, but also the fracture-matrix communication, fingering, and early breakthrough of the injected phases particularly during gas injection processes. This paper provides the key results on the computational fluid dynamics (CFD) simulation of WAG injection in a fractured system. We evaluate the impacts of hysteresis, fracture characteristics (aperture, orientation, and fracture density in the network), and the three-phase relative permeability of available phases during the WAG injection. The CFD model simulates an immiscible WAG injection, and the CFD results are compared to the experimental data in a strongly water-wet sand-pack. Similar to the experiments, we simulate Maroon crude as the oil phase, and synthetic brine, and pure CO2 at 100 °C and atmospheric outlet pressure. The CFD results are in excellent agreement with the experimental data. The absolute relative error is less than 12% for predicting the ultimate oil recovery factors (RFs) in water flooding (WF) and gas injection (GI) cycles. Including the three-phase hysteresis significantly increases the accuracy of the WAG process simulation, while excluding hysteresis underestimates the instantaneous RFs at each cycle (especially GI cycles) and the ultimate RF by 4%. We also analyze the fracture pattern and configuration; adding fractures to the system increases the system effective permeability, leading to more contact between the injecting fluid and trapped oil, and consequently higher oil recovery. Connecting a vertical fracture to the horizontal fracture enhances the recovery through strong connections between the vertical and horizontal blocks. An increase in the fracture aperture from 0.5 to 3 mm increases the RF from 50% to 59%. The fracture inclination angle from 30° to 90° increases the ultimate RF by only 2%. Including gravity forces in vertical model orientation results in overall improvement in RF through engaging both matrix and fracture media in all cycles. As the permeability contrast between the matrix and fracture media decreases, the flow communication between the two regions increases, which improves the recovery performance of the WAG process. Our simulation results can help to further understand the effect of various parameters and operational conditions on WAG injection performance in fractured reservoirs.

Enhancing the Oil Recovery from Naturally Fractured Reservoirs Using Viscoelastic Surfactant (VES) Flooding: A Field-Scale Simulation.

A viscoelastic surfactant (VES) has the combined properties of a surfactant and a polymer. Injection of VES fluids into naturally fractured reservoirs (NFRs) can control the mobility of the injected fluid and enhance the total oil recovery. This paper presents a field-scale simulation to evaluate the performance of a noble VES fluid in enhancing the oil recovery from a naturally fractured reservoir. In this work, the results of coreflooding, computerized tomography (CT)-scan, rheology, interfacial tension (IFT), and adsorption measurements were used to build and calibrate a lab-scale model. Thereafter, a chemical enhanced oil recovery (EOR) modeling simulator developed by a computer modeling group (CMG-STARS) was used to build a field-scale simulation. Real seismic data, permeability and porosity distributions, and operating conditions were utilized to develop and evaluate the simulation model. The results show that VES can outperform the surfactant-polymer (SP) flooding and waterflooding in NFRs; VES improved the oil recovery by 10% and reduced the water cut by 47%, at the same conditions. VES reduced the IFT by two orders of magnitude (100 times) compared to waterflooding. Also, VES altered the rock wettability to a more water-wet status, leading to reduce the relative permeability to water (Krw) by a factor of 10, on average. Finally, the simulation study indicated that applying waterflooding after VES flooding leads to a minor increase in the oil recovery. Overall, this study provides a detailed comparison between VES flooding, SP flooding, and conventional waterflooding in NFRs. Sensitivity analysis was performed to study the impact of treatment parameters on the oil recovery from naturally fractured reservoirs. Using actual NFR data, the optimum VES flooding was determined, which will help in conducting VES flooding for real EOR operations.

A semi-analytical two-phase flow model of fractured horizontal well with complex fracture networks in natural fractured reservoirs

Complex fracture networks are easily developed along the horizontal wellbore during hydraulic fracturing. The water phase increases the seepage resistance of oil in natural fractured reservoir. The flow regimes become more intricate due to the complex fractures and the occurrence of two-phase flow. Therefore, a semi-analytical two-phase flow model is developed based on the assumption of orthogonal fracture networks to describe the complicate flow regimes. The natural micro-fractures are treated as a dual-porosity system and the hydraulic fracture with complex fracture networks are characterized explicitly by discretizing the fracture networks into multiple fracture segments. The model is solved according to Laplace transformation and Duhamel superposition principle. Results show that seven possible flow regimes are described according to the typical curves. The major difference between the vertical fractures and the fracture networks along the horizontal wellbore is the fluid “feed flow” behavior from the secondary fracture to the main fracture. A natural fracture pseudo-radial flow stage is added in the proposed model comparing with the conventional dual-porosity model. The water content has a major effect on the fluid total mobility and flow capacity in dual-porosity system and complex fracture networks. With the increase of the main fracture number, the interference of the fractures increases and the linear flow characteristics in the fracture become more obvious. The secondary fracture number has major influence on the fluid feed capacity from the secondary fracture to the main fracture. The elastic storativity ratio mainly influences the fracture flow period and inter-porosity flow period in the dual-porosity system. The inter-porosity flow coefficient corresponds to the inter-porosity flow period of the pressure curves. This work is significantly important for the hydraulic fracture characterization and performance prediction of the fractured horizontal well with complex fracture networks in natural fractured reservoirs.

The investigation of fracture pattern effect on fluid transport and production prediction in M field

Due to the discontinuity and multi-scale of fracture porous media (FPM), fluid transport in the naturally fractured reservoir (NFR) is more complex than in the conventional reservoirs. Based on the embedded discrete fracture model (EDFM), the effect of fracture pattern (i.e. fracture orientation, intersection relationship, numbers and distribution) on fluid transport is investigated, and the paper also conducts research on pressure distribution and flow behavior. A series of fracture models are built to get a detailed analysis of fracture pattern influences. Results show that when the fracture orientation tends to parallel the main stream direction, the seepage flow through the fracture is more distinct and the pressure drop at two sides of fracture becomes larger. As the intersecting fracture cannot serve as part of main-stream channels, the intersection is almost invalid. In the multi-scale fracture model, the pressure drop in the large-scale fractures network is higher than in the small-scale fractures. Thus, the simulation results show that the fracture pattern has a significant impact on the seepage flow and pressure distribution. Also, this model is simulated for M field which has random natural fracture network to study the flow and transport characteristics in fractured porous media. The comprehensive simulation results the fracture patterns have impact effect on production.

A modified embedded discrete-fracture model to study oil-water two-phase heat and mass transfer in the complex fracture network

The temperature of the fluids injected is usually cooler than the in-situ reservoir temperature in the fractured reservoir's development. It is essential to study thermal changes between matrix and fracture. This paper establishes a fully implicit solution model for the coupling of the oil-water two-phase temperature field and seepage field based on the embedded discrete fracture model (EDFM) method. We deduced the mass and heat transfer between the local matrix grid and the fracture grid by the boundary element method (BEM) instead of a simple linear hypothesis to improve the traditional EDFM method. The model can accurately calculate the seepage field and temperature field in the two-dimensional or three-dimensional problem. Compared with the analytical solution, the discrete fracture model (DFM) and the traditional EDFM method proved that the modified EDFM method could significantly improve the calculation accuracy(especially the temperature field). Furthermore, the modified EDFM method is applied to four examples: waterflooding, huff and puff development, heterogeneous and natural fractured reservoirs, and multilayer enhanced geothermal system (EGS), which verifies the applicability, robustness, and computational convenience, of the new method and illustrates the influence and necessity of considering the coupling effect of temperature field and seepage field on the development effect. It provides an efficient and accurate new method for the study of non-isothermal seepage in fractured reservoirs.

Numerical Well Test Analysis of Condensate Dropout Effects in Dual-Permeability Model of Naturally Fractured Gas Condensate Reservoirs: Case Studies in the South of Iran

Naturally fractured reservoirs (NFR) represent an important percentage of worldwide hydrocarbon reserves and production. The performance of naturally fractured gas condensate reservoirs would be more complicated regarding both rock and fluid effects. In contrast to the dual-porosity model, dual-porosity/dual-permeability (dual-permeability) model is considered as a modified model, in which flow to the wellbore occurs through both matrix and fracture systems. Fluid flow in gas condensate reservoirs usually demonstrates intricate flow behavior when the flowing bottom-hole pressure falls below the dew point. Accordingly, different regions with different characteristics are formed within the reservoir. These regions can be recognized by pressure transient analysis. Consequently, distinguishing between reservoir effects and fluid effects is challenging in these specific reservoirs and needs numerical simulation. The main objective of this paper is to examine the effect of condensate banking on the pressure behavior of lean and rich gas condensate NFRs through a simulation approach. Subsequently, evaluation of early-time characteristics of the pressure transient data is provided through a single well compositional simulation model. Then, drawdown, buildup, and multirate tests are conducted to establish the condition in which the flowing bottom-hole pressure drops below the dew point causing retrograde condensation. The simulation results are confirmed through well test analysis in both Iranian naturally fractured rich and lean gas condensate fields. Interpretations of simulation analysis revealed that the richer gas is more prone to condensation. When the pressure drops below the dew point, the pressure derivative curves in the rich gas system encounter a more shift to the right, and the trough becomes more pronounced as compared to the lean one.