Gas Oil Gravity Drainage Research Articles

New empirical scaling equations for oil recovery by free fall gravity drainage in naturally fractured reservoirs

Gas-oil gravity drainage is a recognized major contributor to production in fractured reservoirs. While various empirical and analytical methods have been proposed to model this process, many of them contain assumptions that are questionable or require parameters that are not accessible at the field level. The aim of this work is to provide new, easy-to-use scaling equations for estimating the recoverable oil through gravity drainage in naturally fractured reservoirs, considering the effects of resistance capillary pressure. To accomplish this, data from four oilfields undergoing gravity drainage, including rock properties (eight sets), block height (three sets), and fluid properties (four sets), were used to generate a wide range of recovery curves using a single porosity numerical simulation model. Aronofsky's and Lambert's functions were then utilized to match the generated recovery curves. Statistical analysis revealed that the Aronofsky's function is more accurate in replicating the recovery patterns, while the Lambert's function tends to overestimate the early-time oil recovery and underestimate the oil recovery at a later stage in the majority of cases. A sensitivity analysis was subsequently performed, revealing that parameters such as absolute permeability, viscosity of oil, height of block, gas and oil density, characteristics of relative permeability and capillary pressure curves and interfacial tension (IFT) influence the amount of time taken to achieve the final recovery. Of these parameters, absolute permeability has the most significant effect on the amount of time needed to attain the final recovery, while the effect of difference between oil and gas densities is the lowest. Consequently, two different expressions were developed using nonlinear multiple regression analysis of simulated gravity drainage data which can be combined with the Aronofsky model to substitute the rate convergence constant. The new scaling equations include the effects of capillary pressure and other relevant factors in gravity drainage simulations. Both forms show satisfactory accuracy, as evidenced by the statistical parameters obtained (R2 = 0.99 and MSE = 0.0019 for both established correlations). The new correlations were verified using a wide range of oilfield data and are expected to provide a better understanding of the recovery process in naturally fractured reservoirs.

Gas-oil gravity drainage mechanism in fractured oil reservoirs: surrogate model development and sensitivity analysis

Gas-oil gravity drainage mechanism in fractured oil reservoirs: surrogate model development and sensitivity analysis

A General Analytical Solution for Axisymmetric Consolidation of Unsaturated Soil with Impeded Drainage Boundaries

The consolidation of soil is one of the most common phenomena in geotechnical engineering. Previous studies for the axisymmetric consolidation of unsaturated soil have usually idealized the boundary conditions as fully drained and absolutely undrained, but the boundaries of unsaturated soil are actually impeded drainage in most practical situations. In this study, we present a general analytical solution for predicting the axisymmetric consolidation behavior of unsaturated soil that incorporates impeded drainage boundary conditions in both the radial and vertical directions simultaneously. The impeded drainage boundary is modeled using the third kind boundary, and it can also realize fully drained and absolutely undrained ones by changing the drainage parameter. A general analytical solution is developed to predict the excess pore-air and pore-water pressures as well as the average degree of consolidation in an unsaturated soil stratum using the common methods of eigenfunction expansion and Laplace transform. The newly developed solution is expressed in the product of the terms of time, depth, and radius, which are derived using Laplace transform, usual Fourier, and Fourier-Bessel series, respectively. The eigenfunctions and eigenvalues are evaluated from the impeded drainage boundaries in both radial and depth dimensions. Then, the correctness of the proposed analytical solution is verified against the existing analytical solution for the case of traditional boundaries and against the finite difference solution for the case of general impeded drainage boundaries, and excellent agreements are obtained. Finally, the axisymmetric consolidation behavior of unsaturated soil involving impeded drainage boundaries is demonstrated and analyzed, and the effects of the drainage parameters are discussed. The results indicate that the larger drainage parameter generally expedites the dissipations of the excess pore pressures and further promotes the soil settling process. As the drainage parameter increases, its influence gradually diminishes and even can be neglected when it is larger than 100. The general analytical solution and findings of this study can help for better understanding the axisymmetric consolidation behavior of the unsaturated soil stratum in the ground improvement project with vertical drains as well as the gas-oil gravity drainage mechanism in the naturally fractured reservoirs.

Initial screening of new generation chemicals using sandpack flooding tests for recovery improvement of gravity driven steam applications

Reservoirs containing very heavy oil or extremely heterogeneous/fractured geology are not convenient for steam flooding and even cyclic steam injection. But, steam can be used to heat the reservoir and accelerate the recovery by gravity drainage. Two well-known applications of this method are steam assisted gravity drainage (SAGD) and thermally assisted gas oil gravity drainage. Although the latter is not commercially applied, the former is a proven technology with remarkable production in Canada and Venezuela. An alternative is to use chemicals as suggested a few decades ago to alter the interfacial forces and improve microscopic displacement. This paper presents experimental results on testing – the new generation – chemicals for their capability in recovery improvement.Sandpack experiments were conducted to evaluate the incremental in oil recovery by chemical additives compared to sole steam injection. Steam and chemicals were heated and introduced to the system from separate channels at the entrance of the vertically situated sandpack (4 inch length, 2 inch in diameter). The chemicals used include thermally stable surface agents, such as anionic surfactants (AAS J1111, O352, LTS-18), non-ionic surfactants (Tween80/85, Span80/85, Novelfroth190, Triton X-100), a biodiesel (FAME), ionic liquid (BMMIM BF4), high pH solution (NaBO2), solvent (heptane, DME), and nanoparticles (SiO2). The oil selected was 27,000 cP crude.Incremental recoveries were monitored and related to the thermal stability and commercial prices of the chemicals. A comparative analysis was provided as to their contribution to the reduction of the cost (lower SOR) and chemicals were classified based on their recovery improvement performance and thermal stability using thermogravimetric analysis (TGA). Through this experimental schematic, the highest increase in oil recovery was achieved by heptane which was also cheap in comparison to the other tested chemicals. Asphaltene precipitation was quantified by conducting SARA analysis of samples taken from the sandpack flooding experiments. The nanoparticle was placed initially into the core holder and had the second-best performances in the steam-to-oil ratio (SOR). Biodiesel also improved oil recovery, but the effects need to be further investigated. The non-ionic surfactants showed great thermal stability and Span80, Tween80, as well as Novelfroth190, lowered the SOR by improving oil recovery. On the other hand, the injection of LTS-18 as anionic surfactant showed an increment of ultimate oil recovery by around 3%. As a wettability modifier, the ionic liquid proved to be profitable in rising oil recovery from the sandpack experiment in a tertiary and an initial injection attempt; however, the ionic liquid is the most cost-effective chemical of the tested candidates.

Foam Application in Fractured Carbonate Reservoirs: A Simulation Study

Fractured carbonate reservoirs account for 25% of world’s total oil resources and for 90% of Iranian oil reserves. Since calcite and dolomite minerals are oil wet, gas oil gravity drainage (GOGD) is known as the most influencing production mechanism. The most important issue within gas injection into fractured media is the channeling problem which makes the efficiency of gas injection process extremely low. As a solution, foam is used to change the mobility ratio, to increase volumetric sweep efficiency, and to overcome the fingering problem. In this work, we inspected three main influencing mechanisms that affect oil extraction from matrix, namely foam/oil gravity drainage, viscous pressure drop due to foam flow in fractures, and foaming agent diffusion from fractures into the matrixes. Foam injection simulations were performed using CMG STARS 2015, on a single matrix unit model and on some vertical cross section models. A number of sensitivity analyses were performed on foam strength, injection rate, fracture and matrix properties, matrix heights, and the initial oil saturation within matrixes. The results show that the roles of the mass transfer of the foaming agent and viscous pressure drop are significant, especially when matrix average heights are small. Moreover, the mechanism for viscous pressure drop remains unchanged, which continues to aid oil extraction from matrixes while the other two mechanisms weaken with time.

To Depict Oil Extraction Efficiency from Gas Invaded Zone: Simulation Study

Future exploitation scheme of an oil reservoir in each cycle within its production life depends on the profitability of the current extraction scenario compared with predicted recoveries that acquire with applying other available methods. In fractured reservoirs appropriate time to pass from the gas injection process into chemical enhanced oil recovery (EOR) firmly depends on the oil extraction efficiency within the gas invaded zone. Several variables including fluid characteristic, fracture network and matrix units properties, etc., impact gas-oil gravity drainage (GOGD) performance within the gas invaded zone. In this work, CMG GEM and ECLIPSE 300 were used to simulate GOGD mechanism in several 2D cross-sectional models to investigate effects of the matrix height, matrix rock type, fracture network transmissibility, and miscibility conditions on the oil extraction rate, change of average pressure and producing gas-oil ratio (GOR). Results showed that in small heights of the matrix units especially at compacted rock types, GOGD was weak that caused a rapid decrease in oil production rates and early increase in producing GOR. Results also showed that wherever the matrix porosity and permeability values were high, recovery was accelerated and GOR remained constant for longer exploitation times. Furthermore, using high-pressure lean gas injection for miscible GOGD gives higher extraction efficiencies rather than applying rich or enriched gas.

Characterization of Liquid Bridge in Gas/Oil Gravity Drainage in Fractured Reservoirs

Gravity drainage is the main mechanism which controls the oil recovery from fractured reservoirs in both gas-cap drive and gas injection processes. The liquid bridge formed between two adjacent matrix blocks is responsible for capillary continuity phenomenon. The accurate determination of gas-liquid interface profile of liquid bridge is crucial to predict fracture capillary pressure precisely. The liquid bridge interface profile in the absence and in the presence of gravity is numerically derived, and the obtained results are compared with the measured experimental data. It is shown that in the presence of gravity, fracture capillary pressure varies across the fracture, whereas, by ignoring gravitational effects, a constant capillary pressure is obtained for the whole fracture. Critical fracture aperture which is the maximum aperture that could retain a liquid bridge was computed for a range of liquid bridge volumes and contact angles. Then, non-linear regression was conducted on the obtained dataset to find an empirical relation for the prediction of critical fracture aperture as a function of liquid bridge volume and contact angle. The computation of fracture capillary pressure at different liquid bridge volumes, fracture apertures, and contact angles demonstrates that if the liquid bridge volume is sufficiently small (say less than 0.5 microliters), capillary pressure in a horizontal fracture may reach values more than 0.1 psi, which is comparable to capillary pressure in the matrix blocks. The obtained results reveal that the variation of fracture capillary pressure versus bridge volume (which represents liquid saturation in fracture) obeys a trend similar to the case of matrix capillary pressure. Therefore, the capillary pressure of matrix can be applied directly to fractures considering proper modifications. The results of this study emphasize the importance of capillary continuity created by liquid bridges in the performance of gas-oil gravity drainage in fractured reservoirs.

THE ROLE OF FRACTURE CAPILLARY PRESSURE ON THE BLOCK-TO-BLOCK INTERACTION PROCESS

Characterization of fractures and the study of multiphase fluid movement through fractures in fractured porous media present difficult challenges to reservoir engineering. Interaction between porous matrix blocks and fractures plays a significant role in oil recovery from double-porosity reservoirs. The block-to-block interaction (or capillary continuity) between porous matrix blocks is a key contributor to the gas-oil gravity drainage mechanism in the gas-invaded zone of naturally fractured reservoirs, which increases the oil recovery. In a continuum scale, fracture is a part of the stack of blocks where there is a pressure difference between the gas and oil phases inside the fracture (called fracture capillary pressure). However, the physics of this capillary pressure and how it affects the gravity drainage mechanism in a stack of porous matrix blocks through the block-to-block interaction process need to be addressed theoretically. In this work a direct fine-grid numerical simulation along with various fracture capillary pressure models, including zero, constant, and saturation-dependent Brooks and Corey (1964), van Genuchten (1980), and Dindoruk and Firoozabadi (1995) functions, are applied to study their influence on oil recovery and therefore the block-to-block interaction process in fractured porous media. Numerical simulation predictions show the positive effect of fracture capillary pressure on oil recovery of a stack porous matrix blocks. The results reveal that the zero fracture capillary pressure model results in a lower ultimate oil recovery factor (23.8%) as compared to the constant (25.8%) and saturation-dependent Brooks and Corey (1964) (28.1%), van Genuchten (1980) (27.5%), and Dindoruk and Firoozabadi (1995) (24.6%) models. These observations are in good agreement with the results in literature. The findings can improve our understanding of the role of fracture capillary pressure on the block-to-block interaction process, which is important in oil recovery from naturally fractured reservoirs using the gravity drainage mechanism.

Static Stability of Liquid Bridges Between Matrix Blocks of a Gas Invaded Zone of Naturally Fractured Reservoirs

A large portion of oil and gas reservoirs in the world are located in naturally fractured reservoirs. Despite such importunity, the production mechanisms of these reservoirs are not completely well defined. Gas–oil gravity drainage that takes place in the gas-invaded zone of this type of reservoirs is one instance of such a weakness. The density difference between gas-filled fractures in contact with oil-saturated matrix blocks brings the oil out of the matrix blocks into the fracture. The drained oil can reach the production well through two different paths: continues fracture network and block-to-block path. These two different paths require different approaches to modeling of gravity drainage. Single-block approaches are used when drained oil only travels through the fracture network, which totally formulated before. But when oil prefers to travel through the matrix blocks, continuum approaches such as Darcy's law may not work in their basic forms any more. Liquid bridges and film that form in the horizontal fracture between matrix blocks usually transfer the wetting phase across the fracture. Stability condition and duration of stability can help better understanding of gravity drainage in stacks of blocks. In this article, the stability of liquid bridges between the matrix blocks studied and a minimum length of stability is predicated. The results show that this stable length of liquid bridges formed between adjacent matrix blocks is 2r0π, which is a function of the pore throat. This critical length can be used in modeling of capillary continuity and wetting phase transfer across matrix blocks.

Proper Implementation of Gas-oil Gravity Drainage Transfer Functions in Dual Porosity Simulators

Free fall and forced gravity drainage are established production mechanisms, which contribute to significant oil production in naturally fractured reservoirs, commonly 30–60% original oil in place. Accurate and proper implementation of gravity drainage performance, as an exchange term, in dual porosity simulators is a critical issue. A numerical model of gas-oil gravity drainage was developed and solved analytically for some simple cases and also numerically for more complicated forms of capillary pressure and relative permeabilities. In this article, three famous transfer functions in the literature in a comparative study were checked by a developed numerical model. The result revealed that transfer functions studied here predict less accurate results in comparison with the numerical model and using constant matching parameters cannot resolve this issue because problems arise from simple treatment of time dependent parameters, such as capillary pressure and relative permeability.

Fracture Capillary Pressure Based on the Liquid Bridge Dynamic Stability Study

Performance study of gas oil gravity drainage in stacks of overwhelmed blocks in a gas-invaded zone of naturally fractured reservoirs presents difficult challenges to petroleum engineers. It is believed that there exists some degree of block-to-block interaction that may lead to capillary continuity in fractured reservoirs. Effect of such continuity in gravity drainage is much more pronounced as it increases the height of the continuous fluid column in a reservoir and thereby the recovery of oil as height is a key parameter in gravity drainage mechanisms. It has been experimentally proven that liquid or solid bridges in horizontal fracture can contribute to wetting phase transfer across the horizontal fracture, but there is no mathematical model that predicts the probability of such continuity. In this article, a mathematical model developed by using 1-D Navier-Stock for the free surface flow equation and Young-Laplace of capillary for breakage of the stable liquid bridge held between two pairs of support while stretching. The model gives critical length of fracture aperture, which surely provides capillary continuity. Moreover, the developed model shows flow dependency of fracture capillary pressure and predicts a nonzero value for this parameter, while in the past many researchers used zero fracture capillary pressure for history matching of fractured reservoirs.

Secondary and Tertiary Thermally Induced Gas-oil Gravity Drainage from Oil-wet Fractured Rocks: Experiments under Reservoir Conditions

A series of reservoir condition experimental studies are presented that investigate the effects of oil production by water drive on the success of subsequent oil production by gas-oil gravity drainage in a fractured laboratory model. The experiments were performed using low permeable, oil-wet carbonate core samples. During this work, injection of N2 gas followed by steam into the fracture was studied using two different scenarios: initial oil place at connate water saturation condition utilized for secondary oil recovery, and water flooded cores at residual oil saturation for tertiary oil recovery. The result showed that the water invasion into the fractures reduces oil production potential, and it is shown that the ultimate recovery for secondary gas injection is considerably higher than tertiary gas-oil gravity drainage for both isothermal and non-isothermal tests. Steam injection into the fractured model leads to twice more oil recovery than the preceding isothermal recovery. The results confirmed that the key oil production mechanism during non-isothermal gas-oil gravity drainage that initiates the main phase of oil production is heat transfer into the matrix blocks and viscosity reduction. In addition, results of contact angle measurements showed that wettability of the oil wet rocks after steam flooding was shifted to neutral wet condition that increase gravity drainage performance.

Multiscale Simulation of WAG Flooding in Naturally Fractured Reservoirs

This article, written by Special Publications Editor Adam Wilson, contains highlights of paper SPE 164837, ’Multiscale Simulation of WAG Flooding in Naturally Fractured Reservoirs,’ by Mohamed Ahmed Elfeel, Adnan Al-Dhahli, Sebastian Geiger, SPE, and Marinus I.J. van Dijke, Heriot-Watt University, prepared for the 2013 EAGE Annual Conference and Exhibition/SPE Europec, London, 10-13 June. The paper has not been peer reviewed. Naturally fractured reservoirs (NFRs) contain a significant amount of remaining petroleum reserves and are now being considered for water-alternating-gas (WAG) flooding as secondary or tertiary recovery. The authors face the challenge of reservoir simulation of WAG by building models at various scales, starting with pore scale and expanding to an intermediate scale and then to reservoir scale. They show how pore-network modeling and fine-grid modeling where the fractures and matrix are represented explicitly can be used to increase the accuracy of numerical simulations at field scale. Introduction A significant portion of the world’s remaining petroleum resources is located in NFRs, including supergiant fields in the Middle East. A detailed understanding of the recovery processes involved in extracting hydrocarbons from NFRs by use of enhanced-oil-recovery techniques is key to increasing ultimate recovery for such reservoirs. Waterflooding has been used with various degrees of success in NFRs. For unfavorable (i.e., mixed- to oil-wet) matrix wettability, however, waterflooding can be ineffective. Gas/oil gravity drainage (GOGD) provides an important drive mechanism that can be effective irrespective of the rock wettability. In NFRs, fractures increase the exposure of the injected gas to oil in reservoir rock, which renders GOGD more effective than it is in unfractured reservoirs. Consequently, gas injection has been applied in many NFRs. However, because the gas mobility is very high compared with that of water and oil, so is the risk of bypassed oil and gravity override, which can lead to very early gas breakthrough. This is particularly true for NFRs. WAG flooding combines the merits of the two injection fluids on macroscopic and microscopic scales while stabilizing the injection front, delaying breakthroughs, and, therefore, leading to increased oil recovery compared with continuous water or gas injection. Reservoir simulation of WAG injection is very challenging because a representative three-phase saturation model is required to predict relative permeability and capillary pressure as water and gas saturations increase and decrease alternately. Three-phase relative permeability and capillary pressure data are extremely difficult to measure experimentally. Even if experimental evaluation becomes feasible, an infinite number of saturation paths can occur in the reservoir. This necessitates the use of empirical, or interpolation, models to predict three-phase relative permeability and capillary pressure from two-phase experiments. In NFRs, capillary pressure and relative permeability functions have a major effect on fluid exchange between matrix blocks and fractures. Predicting the effects of the interplay of viscous, capillary, and gravity forces is challenging because fluid flow is viscous-dominated in the fractures while transfer between fractures and matrix blocks is dominated by capillary and gravity forces. Because most of the oil is contained inside the matrix, capillary and gravity forces can be more important in NFRs than in conventional reservoirs.

Integrating Well, Reservoir, and Facility Management Improves Field's Production

This article, written by Special Publications Editor Adam Wilson, contains highlights of paper IPTC 16523, ’Oman's Large-Carbonate-Field Production Improvement Through Integrated Well, Reservoir, and Facility Management,’ by S.M. Al-Khadhuri, M.M. Al-Harthi, and A. Alkalbani, Petroleum Development Oman, prepared for the 2013 International Petroleum Technology Conference, Beijing, 26-28 March. The paper has not been peer reviewed. A carbonate field developed by Petroleum Development Oman is one of the largest fields in the Sultanate of Oman and has been running for more than 4 decades. An integrated wells, reservoir, and facility management approach has been implemented to create more focus and discipline with the aim of achieving an efficiently monitored and controlled asset and highly synchronized multiteam actions. Introduction The field is located in the north of the Sultanate of Oman, and it is one of Oman’s largest fields. The reservoir layers dip uniformly at 15° to the northeast (Fig. 1). The field is a highly complex carbonate reservoir of the Natih formation and is subdivided into seven units, Natih A through Natih G, and the Shuabia reservoir. It has been running since 1967 and continues to contribute significantly. The development strategy began with natural depletion with vertical wells and followed with two mechanisms, gas/oil gravity drainage (GOGD) and waterflood. The GOGD process concentrates more on fractured reservoir rock, while the waterflood process targets the layers with a relatively low degree of fracturing. The GOGD development consists of five crestal gas-injection wells and rows of down-flank producers that tap oil from a fractured oil rim. The reservoir pressure is managed by gas injection. The gas-injection rates are set to replace voidage and to maintain reservoir pressure. For the matrix wells, the reservoir pressure is managed by waterflood (water injection). This combination of different drive mechanisms in a highly fractured reservoir that yields to interference and gas/water short-circuiting makes the management of the field very challenging. To overcome these challenges, an integrated well, reservoir, and facility management strategy has been established in a way that ensures integration with multiple disciplines and uses many tools. As a result, an improvement in production has been seen that reflects successful implementation of the strategy. Wells and Reservoir Reviews Wells are reviewed on a yearly basis in order to have a systematic approach for reviewing wells. Approximately 26 sectors (more than 450 wells) from different reservoirs have been reviewed collaboratively. Multidisciplinary involvement from the well and reservoir management (WRM) team, the development and planning (DP) team, and the new oil (NO) team, and alignment to mature identified activities, played a crucial role in effectively sharing ideas and lessons learned and implementing activities.

Effect of Non-equilibrium Gas Injection on the Performance of (Immiscible and Miscible) Gas–Oil Gravity Drainage in Naturally Fractured Reservoirs

In naturally fractured reservoirs, improving the matrix–fracture interactions is critical to the success of the applied improved oil recovery method. Therefore, a study of the mechanisms that control the mass exchanges between fracture and matrix can help to optimize recovery. This paper concerns an experimental and simulation study to investigate the performance of the gas–oil gravity drainage process in naturally fractured reservoirs. In this study, five gas injection experiments were conducted at different miscibility (i.e., immiscible and fully miscible) conditions using CO2, N2, and a synthetic flue gas composed of 20% (v/v) CO2 and 80% (v/v) N2. The impact of switching from an immiscible (i.e., nitrogen or flue gas) gas to a non-equilibrium and fully miscible CO2 injection is investigated. The effect of miscibility on the block–block interaction is also examined using a stacked core with an impermeable barrier. The results reveal that injection of non-equilibrium gas with higher solubility in the oil phase results in a zone of decreased oil viscosity, which leads to an improved gravity mediated recovery. The results also show that the ultimate oil recovery increases considerably once miscibility is achieved. A numerical model is implemented to perform compositional simulations of multiphase, multicomponent gas injections at different miscibility conditions. Agreement of the developed model with the experimental results indicates that gravity drainage, capillary holdup, and mixing are the main controlling mechanisms.

Foam assisted gas–oil gravity drainage in naturally-fractured reservoirs

This paper introduces an enhanced-oil-recovery concept for naturally-fractured reservoirs. We use foam to improve the gas–oil gravity drainage process in the fractured reservoirs. We developed an expression that approximates the maximum oil rate depending on the injected gas rate and average properties of the foam generated in the fracture, which provides results that are in good agreement with the numerical results. We use two different foam models to simulate foam behavior in the matrix and the fracture. For the fracture we use the model developed by Hirasaki and Lawson (Hirasaki, G.J., Lawson, J.B., 1985. Mechanisms of foam flow in porous media: apparent viscosity in smooth capillaries. SPE J., 176–190), which considers the effects of flowrate, interfacial tension, and foam quality on the foam rheology. For the matrix we use the empirical foam model (mobility reduction model), which scales down the gas mobility based on empirical parameters. It is shown that foam generation in the fracture creates a viscous pressure drop along the fracture that is directly transferred to the oil-bearing matrix and accelerates oil production. It is also shown that gas and water are simultaneously diverted into the matrix via the creation of a horizontal pressure drop between the fracture and the matrix. This has consequences for foam rheology in the fracture as it change the local foam quality along the fracture. The effects of relevant physical parameters on the efficiency of the mechanism are also discussed in the paper.

A new analytically derived shape factor for gas–oil gravity drainage mechanism

Matrix–fracture exchange term is an important parameter in simulation of naturally fractured reservoirs using double porosity concept. A matrix block which is located in gas-cap is going to be produced under gravity drainage retarded by capillary force. Hence, oil can be produced as long as gravitational force is greater than the capillary force. The interaction of these forces which controls the oil production from a matrix block may be expressed by a factor which is matrix–fracture transfer shape factor. Customarily, this factor has been used as a history matching parameter as it is still not well understood and the formulations used in commercial simulators are not precise. Therefore, a mathematically derived shape factor which reflects the gravity drainage behavior into an exchange term using shape factor concept is essential. Traditionally, a constant shape factor has been used in most of the commercial reservoir simulators. In this paper, we use analytical modeling to develop a time dependent shape factor for gas–oil gravity drainage mechanism for a single matrix block in a gas-cap. The obtained model is verified against several fine-grid numerical simulations as well as two major existing models being used in a commercial simulator. The obtained shape factor starts from a dimensionless shape factor of 2 ( σL z 2 = 2) and demonstrates a transient behavior at early times and then converges to π 2/4 at late times. The capillary force distribution throughout the matrix block is also obtained during the process showing a nonlinear distribution at early times which turns into a linear one at late times. The linear behavior of capillary force distribution corresponds to late time stabilization of shape factor. Moreover, the mathematical derivation predicts very early time constant maximum drainage rate after which drainage rate starts to decline. The results obtained in this paper will improve our understanding of the gas–oil gravity drainage in fractured reservoirs and will find application in more accurate representation of this process in dual-porosity simulators.

THE GAS-OIL GRAVITY DRAINAGE MODEL IN A SINGLE MATRIX BLOCK: A NEW RELATIONSHIP BETWEEN RELATIVE PERMEABILITY AND CAPILLARY PRESSURE FUNCTIONS

This work concerns modeling of gas-oil gravity drainage for a single block of naturally fractured reservoirs. The non-linearity induced from saturation-dependant capillary pressure and relative permeability functions makes a gravity drainage model difficult to analytically and numerically solve. Relating the capillary pressure and relative permeability functions is a potential method to overcome this problem. However, no attempt has been made in this regard. In this study a generalized one-dimensional form of gas-oil gravity drainage model in a single matrix block, presented in the literature, is considered. In contrast with commonly used forms of capillary pressure and relative permeability functions, more realistic models, which are in power law, are used in the model. It has been found that the nonlinearity of the generalized model is canceled only if the powers of capillary pressure and relative permeability functions are related as n = m + 1. The Fourier Laplace inversion method is applied to numerically solve the developed model and generate the drainage flow rate and the oil saturation profiles at different values of m and n powers. The results of this work might help to obtain a new transfer function for a dual-porosity model, which might improve the reliability of simulators for evaluation of naturally fractured reservoirs.

Numerical Simulation and Sensitivity Analysis of Gas-Oil Gravity Drainage Process of Enhanced Oil Recovery

Abstract The oil recovery process is controlled by the rates of gas injection and oil production, relative permeabilities, reservoir heterogeneities and the balance among viscous, capillary and gravity forces. Crestal gas injection in horizontal, vertical or reef type oil reservoirs recovers significant volumes of the residual oil due to the gas-oil gravity drainage mechanism, indicating the significance of gravity forces. This study investigates the effects of the parameters that control the process (e.g., rate of the gas injection and oil production) and reservoir heterogeneities on the overall performance of immiscible gravity drainage enhanced oil recovery (EOR). Reservoir simulation studies are conducted to map effective combinations of these parameters with respect to the oil recovery performance. Introduction Gravity forces play an important role at nearly every stage of the producing life of the reservoir, whether it is primary depletion, secondary water or gas injection schemes or tertiary enhanced or improved oil recovery methods(1). They can be advantageously used to maximize oil recovery from the oil bearing zone under investigation through gravity drainage mechanism. Several cases reported in the literature suggest that it could deliver as high as 87 to 95% incremental oil recoveries in contrast to other gas injection EOR methods. Gas-Oil Gravity Drainage Process Gravity drainage is a process in which gravity acts as a main driving force and where gas replaces voidage volume(2). It is commonly implemented in either of the dipping or pinnacle reef type reservoirs. CO2-assisted gravity drainage EOR process is a top-down process in which gas is injected in the gas cap through vertical wells at a rate lower than the critical rate (Figure 1). Critical rate is the rate at which injection gas fingers through oil zone (viscous instabilities) leading to its premature breakthrough at the production wells. Injected gas segregates and creates a gas-oil interface. Controlled oil production is started through horizontal wells placed at the bottom of the oil zone such that the voidage created by oil withdrawal (in addition to minor dissolved volumes) is replaced by the equivalent CO2 injection volume. When this happens, pressure differential across the gas cap and oil zone [that is gas-oil contact (GOC)] stay at or close to zero implying that the pressure in the gas zone behind the CO2 floodfront would be constant(3). This helps to maintain the reservoir pressure nearly constant.

Low IFT gas–oil gravity drainage in fractured carbonate porous media

This paper addresses a study of gas–oil gravity drainage in fractured carbonate rock subjected to gas injection in low interfacial tension. The purpose of the experiments described in the paper was to investigate gas injection in fractured carbonate reservoirs in both secondary and tertiary cases (after water injection), focusing on gravity drainage using equilibrium gas followed by re-pressurization. Gas injection experiments were performed on 20 cm long and low permeable outcrop chalk core surrounded with a fracture established with a novel experimental set-up in reservoir conditions. The core was saturated with binary mixture live oil consisting of C 1 and C 7 of a known composition, while the fracture was filled with sealing material to obtain a homogeneous saturation. After core initialization, the sealing material was removed by increasing the temperature to higher than its melting point and displaced by live oil. Gas was then injected into the fracture and gravity drainage experiments were performed in low interfacial tension (< 0.5 mN/m) where the IFT between the phases were measured experimentally by selecting the proper pressure and temperature. Experiments were performed at different pressures and reversibility of the effect of the interfacial tension was checked by re-pressurization process. The oil recovered from the bottom side of the block was measured versus time. Based on the results of this study, the recovery of oil showed a significant increase by re-pressurization in gravity drainage process. It was also clear that low IFT gravity drainage is capable to recover a significant amount of oil in fractured reservoirs even after water injection.