Effects Of Reservoir Heterogeneity Research Articles

Effect of reservoir heterogeneity on well placement prediction in CO2-EOR projects using machine learning surrogate models: Benchmarking of boosting-based algorithms

Rising Carbon Dioxide (CO2) levels from human activities are driving climate change. Carbon capture and storage (CCS) during enhanced oil recovery (EOR) in underground reservoirs offer both environmental and economic benefits. This method boosts oil production, cuts greenhouse gas emissions, and supports sustainable energy. Precise well placement in CO2-EOR is a crucial task for effective oil displacement, but traditional reservoir simulators are costly. This study explores and compares boosting algorithms, as fast surrogate models, to achieve accurate well placement during CO2-EOR in light oil carbonate reservoirs. The research considers various reservoir scenarios with different geological heterogeneity levels (i.e., homogeneous, moderately heterogeneous, and highly heterogeneous reservoirs). Various parameters, such as injection and production well locations, the distance between production and injection wells in an inverted five-spot pattern, pattern angle, and injection and production rates are explored using a compositional reservoir simulator to assess their impact on the well placement problem. A comprehensive analysis of various boosting algorithms, including AdaBoost, CatBoost, Gradient Boosting, LightGBM, and XGBoost is performed using the simulated dataset to assess their efficacy. The results demonstrate that LightGBM outperformed the other algorithms with the lowest Mean Absolute Error and Root Mean Square Error of 115.3 × 106 $ and 188.2 × 106 $, respectively. Additionally, it demonstrates exceptional speed, averaging 3 to 8 times faster than other boosting algorithms in the three reservoir scenarios. This superior performance coupled with its efficient runtime makes LightGBM the ideal choice for the study objectives. Moreover, the mass balance approach highlights the significant CO2 storage efficiency, emphasizing the effectiveness of CO2-EOR in storing CO2 in underground heterogeneous reservoirs.

Flow parameter setting methods in numerical simulation of the unconventional reservoir and its impact on production

Abstract Tight reservoirs have poor physical properties and complex pore structures, and well production is often affected by the starting threshold gradient, stress sensitivity, and water blockage. In this paper, the numerical simulation method is used to make these three factors equal. In addition, normalized influence coefficient analysis and grey relation analysis are used to investigate the degree of influence of each factor on well production. In this study, three methods are developed to set the threshold pressure gradient according to the permeability zoning, and the effect of reservoir heterogeneity is considered to set the threshold pressure gradient for unconventional reservoirs. The equivalent accuracy of the numerical simulation of the threshold pressure gradient can be improved compared to the traditional method. Stress sensitivity and water blockage effects are equated by correcting for rock compressibility coefficient and gas relative permeability. The fit rate of the gas well production history is improved by 2–3% after considering complex factors. The inclusion of the complex factors reduces the reservoir energy mobilization. The threshold pressure gradient results in an additional pressure reduction of about 1.8 MPa around the gas well. Residual gas identification and development is helped by clarifying the effect of complex factors on formation pressure When only the effect of a single factor is considered, water blockage has the most significant effect on gas well production, followed by threshold pressure and the weakest stress sensitivity. When several factors are considered together, the effect of stress sensitivity is increased.

Effects of Reservoir Heterogeneity on CO2 Dissolution Efficiency in Randomly Multilayered Formations

Carbon dioxide (CO2) dissolution is the secondary trapping mechanism enhancing the long-term security of CO2 in confined geological formations. CO2 injected into a randomly multilayered formation will preferentially migrate along high permeability layers, increasing CO2 dissolution efficiency. In this study, sequential Gaussian simulation is adopted to construct the stratified saline formations, and two-phase flow based on MRST is established to illustrate the spatial mobility and distribution of CO2 migration. The results show that gravity index G and permeability heterogeneity σY2 are the two predominant factors controlling the spatial mobility and distribution of CO2 transports. The CO2 migration shows a totally different spatial mobility under different gravity index and heterogeneity. When the permeability discrepancy is relatively larger, CO2 preferentially migrates along the horizontal layer without accompanying the vertical migration. For the formation controlled by gravity index, CO2 migration is governed by supercritical gaseous characteristics. For the medium gravity index, the upward and lateral flow characteristics of the CO2 plume is determined by gravity index and heterogeneity. When the gravity index is smaller, permeability heterogeneity is the key factor influencing CO2 plume characteristics. Permeability heterogeneity is the decisive factor in determining final CO2 dissolution efficiency. This investigation of CO2 mobility in randomly multilayered reservoirs provides an effective reference for CO2 storage.

Lower limits of petrophysical parameters for effective reservoirs in ultradeep carbonate gas reservoirs: A case study from the Deng IV Member, Gaoshiti-Moxi Area, Sichuan Basin, SW China

Lower limits of petrophysical parameters (LLPP) of effective reservoirs are significant parameters for reserve evaluation and exploitation scheme formulation of hydrocarbon reservoirs. However, the existing LLPP determination method is not applicable to ultradeep carbonate reservoirs with diverse reservoir space and strong heterogeneity. Therefore, a systematic method for determining the LLPP of ultradeep carbonate gas reservoirs was developed in this study. First, the geological setting and reservoir characteristics were briefly introduced, and numerous cores were classified according to whether cavities and fractures were developed. Subsequently, the test data of petrophysical property, NMR, high-pressure mercury intrusion (HPMI), and fluid physical property were collected, and a series of LLPP values were obtained through static methods of cumulative frequency statistics, porosity–permeability relationship, irreducible water saturation, and minimum flowable pore throat radius (Rmin). The LLPP determined by static methods were then verified by dynamic methods of gas well testing, productivity model prediction, and productivity simulation experiment, and the LLPP of reservoirs that can form industrial gas flow were determined. Finally, the effect of reservoir heterogeneity on LLPP was revealed, the applicability of various LLPP determination methods were summarized, and the accuracy of the obtained LLPP was confirmed by well testing interpretations. The research results show that the reasonable classification of reservoir types is the prerequisite to accurately determine the LLPP of carbonate reservoirs. The lower limit of porosity is little affected by cavities, while the lower limit of permeability is greatly affected by fractures. Rmin of ultradeep carbonate reservoirs obtained by HPMI test and water film thickness calculation is approximately 60 nm. The significant heterogeneity of carbonate reservoirs requires that effective reservoirs should reach the lower limit of porosity and permeability simultaneously. LLPP determined through static methods and dynamic methods can be applied to evaluate geological and dynamic reserves, respectively. The LLPP of effective reservoirs that allow gas to accumulate, migrate, and form industrial gas production are 2.68% and 0.042 mD.

Effect of Reservoir Heterogeneity on CO2 Flooding in Tight Oil Reservoirs

Carbon dioxide (CO2)-enhanced oil recovery (EOR) has great potential and opportunity for further development, and it is one of the vital carbon capture, utilization, and storage (CCUS) technologies. However, strong heterogeneity is one of the several challenges in developing reservoirs, especially for China’s continental tight oil reserves. This study investigates the effects of heterogeneous porosity and permeability on CO2 flooding evolution in low-permeable tight formation. We simulated CO2-EOR using a numerical model developed on the platform of TOUGH2MP-TMVOC to evaluate the effect of different levels of heterogeneity on oil production, gas storage, and flow behaviors in a tight reservoir, controlled by standard deviation and correlation length. A comparison of nine cases reveals that porosity heterogeneity commonly intensifies flow channeling, and there is an oil production decline with higher standard deviation and longer correlation length of porosity field. In addition, the porosity correlation length has a negligible effect on reservoir performance when the standard deviation is relatively low. Furthermore, strong heterogeneity also has a negative impact on the storage capacity of CO2 and oil production. Notably, as the standard deviation was raised to 0.1, a small sweep region arose with the early CO2 breakthrough, which led to a worse flooding effect. Finally, this study exemplifies that a higher injection/production rate and CO2 alternating N2 injection strategies can improve oil recovery in highly heterogeneous reservoirs.

Investigation of the influence of the heterogeneous permeability distribution on the oil phase displacement processes

The object of research is the filtration processes of displacement of the oil phase under the influence of an injection well in a heterogeneous porous medium. It is possible to evaluate and take into account the effect of reservoir heterogeneity on the distribution of reservoir pressure (and, consequently, on the intensity of the filtration process) using numerical modeling of filtration processes based on the piezoelectric equation. To solve the non-stationary anisotropic problem of piezoconductivity, it is proposed to apply the combined finite-element-difference method of M. Lubkov, which makes it possible to take into account the inhomogeneous distribution of permeability inside the anisotropic oil-bearing formation and at its boundaries, and to adequately calculate the distribution of reservoir pressure. The use of the combined finite-element-difference method allows to combine the advantages of the finite-element method and the finite difference method: to model geometrically complex areas, to find the value at any point of the object under study. At the same time, the use of an implicit difference scheme when finding the nodal values of the grid provides high reliability and convergence of the results. The simulation results show that the distribution of the pressure field between the production and injection wells significantly depends on their location, both in the isotropic landslide and in the anisotropic oil-bearing reservoir. It is shown that the distance between the wells of more than 1 km levels out the effectiveness of the impact of the injection well on the oil filtration process. The influence of the permeability of the oil phase in the shear direction dominates the influence of the permeability in the axial directions (affects the pressure decrease by 4–9.5 %). In the case of a landslide-isotropic reservoir, the wells should be located in the shear (diagonal) direction, which will provide the lowest level of drop in the average reservoir pressure (by 4 %). Based on the information obtained, for the effective use of anisotropic low-permeability formations, it is necessary to place production and injection wells in areas with relatively low anisotropy of the formation permeability, especially to avoid places with the presence of landslide permeability of the formation. The location of the wells is important so that, on the one hand, there is no blockage of oil from the side of reduced permeability, and on the other hand, rapid depletion of the formation from the side of increased permeability does not occur. And also the mutual exchange between the production and injection wells did not stop. When placing a system of production and injection wells in anisotropic formations of an oil field, it is necessary to carry out a systematic analysis of the surrounding anisotropy of the formations in order to place them in such a way that would ensure effective dynamics of filtration processes around these wells. Using the method used, it is possible to predict the impact of an injection well on the distribution of reservoir pressure in the reservoir.

Numerical Simulation of Channelization Near the Wellbore due to Seepage Erosion in Unconsolidated Sands during Fluid Injection

The channels may be formed in the unconsolidated sands reservoir due to formation failure during high-pressure water injection or frac-packing. Based on the continuum mechanics, a mathematical model has been established to simulate the formation process of big channels in unconsolidated sands reservoir during fluid injection. The model considers the effect of reservoir heterogeneity, solid particles erosion, and deposition. The dynamic formation process of channels around the borehole and its influencing factors are analyzed by this model. The results indicate that the seepage erosion plays a very significant role in the formation of the channels during fluid injection for the unconsolidated sands with extremely low strength. The formation of the channels is closely related to the duration of fluid injection, injection pressure, reservoir heterogeneity, formation plugging, and critical fluid velocity. The long channels are more likely to form as injection time increases. Higher injection pressure will lead to higher flow rate, thus eroding the solid particles and forming big channels. The increase of the rock strength will enhance the value of critical fluid velocity, which makes it difficult for the occurrence of erosional channelization. The near-wellbore damage of the formation will decrease the flow rate, and the preferential flow channels are less likely to be induced under the same injection pressure when compared with undamaged formation. In addition, we also found that the reservoir heterogeneity is essential to the formation of preferential flow channels. The channels are especially prone to be formed in the regions with high porosity and permeability at the initial time. The study can provide a theoretical reference for the optimal design of high-pressure water injection or frac-packing operation in the unconsolidated sands reservoir.

Sustainable electricity generation from an Enhanced Geothermal System considering reservoir heterogeneity and water losses with a discrete fractures model

Electricity production from Enhanced Geothermal System (EGS) is faced with premature thermal breakthrough due to the preferential flow path of the geofluid which is the consequence of the reservoir heterogeneity. Heat extraction investigation has been performed with assumptions of no water losses, isotropic and homogeneous reservoir. However, EGS reservoir is heterogeneous due to the preexistence of natural fractures and different formations. Water injection under high pressure causes water losses from reservoir boundaries to surrounding formations. Considering reservoir heterogeneity, permeability anisotropy, and water losses is required for reliable assessment of heat extraction. These important aspects were considered in this study and the effects of reservoir heterogeneity, water losses, wells spacing, wells orientation, regional flow direction, injection temperature on system performance with a discrete fractures model were analyzed. Neglecting water losses and assuming homogeneous reservoir overestimate the system performance. The maximum electric power is obtained for vertical wells with 540 m of wells spacing, the thermal breakthrough time is 25.6 years, and the average electric power is 9.7 MWe. Water losses from 0% to 10% lead to a decrease in energy efficiency from 2.4–2.2 to 2.3–2.1. The regional flow direction from the production well to the injection well improves the system performance.

Numerical study on the effect of reservoir heterogeneity and gas supply on hydrate accumulation in subsea shallow formations

Seepage-type gas hydrate accumulation in subsea shallow formations involves complicated thermo-hydro-solid coupling processes and matching problem between various accumulation elements. The formation physical properties control local natural gas migration pathway and thus the final reservoir characteristics of hydrates. In this paper, a novel mixed-flux model for gas hydrate accumulation is established and then used to simulate the process of methane gas migration into the shallow stratum to form a hydrate reservoir. The effects of reservoir heterogeneity and gas source conditions on the distribution of pore fluid and hydrate accumulation are examined. The simulation results show that reservoir heterogeneity is conducive to the retention and lateral migration of CH4 in a hydrate stability zone. CH4 can contact more pore water to form a large hydrate reserve, but the formed hydrate is often dispersed. Low-permeability layers enhance the trapping of CH4 and form a uniform and large hydrate saturation. Besides, gas source conditions have an important impact on the hydrate accumulation in reservoirs. Large gas flux, small pore water flux, continuous gas supply, high content of heavy components in natural gas, and numerous gas source points contribute to large amounts of hydrates generation in a certain time period. The presented work will deepen our understanding of the controls of natural gas hydrate systems in subea shallow formations.

Semianalytical Analysis of Chamber Growth and Energy Efficiency of Solvent-Assisted Steam-Gravity Drainage Considering the Effect of Reservoir Heterogeneity along the Horizontal Well

Solvent-Assisted Steam-Gravity Drainage (SA-SAGD) has lately been viewed as one of the most efficient alternatives to develop heavy oil reservoirs. However, there is strong evidence that reservoir ...

Analysis of Athabasca Oil Sands Investigates SAGD Performance Variability

This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper SPE 195348, “Steam-Assisted Gravity Drainage Performance Variability—Analysis of Actual Production Data for 28 Athabasca Oil Sands Well Pairs,” by Quang T. Doan, Vincano; S.M. Farouq Ali, SPE, University of Houston; and Thomas B. Tan, SPE, Petrostudies Consultants, prepared for the 2019 SPE Western Regional Meeting, San Jose, California, 23–26 April. The paper has not been peer reviewed. Steam-assisted gravity drainage (SAGD) performance in bitumen-recovery projects in Alberta is affected by geological deposits, reservoir quality, and operational experience. The authors reviewed and analyzed actual field production and injection data for 28 Athabasca oil-sands-deposit SAGD well pairs (WPs). Based on analysis of field-production data, a numerical model was built and calibrated against production data from two of the poorer-performing WPs among the 28 studied. Agreement between simulated and actual cumulative oil and steam/oil ratio (SOR) was within 10% after 6 years of operations on a first-iteration basis. Problem and Investigation Methodology A survey of the literature reveals that some aspects of the SAGD process, particularly with regard to the behavior of gas, still largely are not understood. While successful history-matching simulations of SAGD WPs exist for several different projects, these rely on dead-oil pressure/volume/temperature treatment and exclude any findings and discussion on gas production. Such history-matched models likely would need to be modified significantly to be useful for modeling the wind-down stage of SAGD operations. Recent numerical studies modeling the generation of aquathermolysis gases focused on the injection of noncondensable gas into a mature SAGD steam chamber. In preparation for a series of numerical studies on aspects of SAGD performance, a reservoir model simple enough to be relatively adaptable for different geological settings was built. Such a model had to be calibrated rigorously with actual production data to provide a high degree of confidence in its results and predictive capability in appropriate contexts. The investigation in the complete paper is aimed at addressing several fundamental aspects of SAGD operations, including the effects of reservoir heterogeneities and the behavior of gas. The first part of the complete paper is focused on reviewing and analyzing actual field production data spanning more than 1,700 days from 28 SAGD WPs from four different pads (A, B, C, and D) of the Jackfish 1 project; this synopsis will not include that extensive data. Jackfish 1 Project. Jackfish 1 consists of 42 WPs divided into six pads (including the 28 WPs in Pads A, B, C, and D analyzed for the authors’ study) and is part of the geological oil-sands trend of the Athabasca oil-sands deposit. Jackfish 1 has a nameplate capacity of 35,000 BOPD, with a designed SOR of 2.7. Consistently exceeding 90% of its nameplate capacity since first steam, it is commonly considered to be a successful SAGD project. The results of data analysis for the WPs studied indicated the following: Considerable variance exists in the recovery performance of SAGD WPs on the same pad. Considering the small drainage area of the 7-WP pad (800×800 m), such variances bear important implications for the planning and execution of SAGD projects (particularly greenfield development but also with regard to brownfield expansion). The authors stress that forecasting project productivity should not be based on a single-WP, deterministic simulation model without any consideration for distributions in reservoir geology and parameters affecting SAGD performance. This assessment is equally applicable in the estimation of reserves.

Estimating local capillary trap volume capacities using a geologic criterion

Capillary pressure heterogeneity causes local capillary trapping of CO2 in saline aquifers. However, quantifying local capillary trapping using conventional reservoir simulation is computationally intensive. This work employs a geologic criterion (GC) to rapidly estimate the volume capacity of local capillary traps in static geologic models. The criterion refers to the ‘critical capillary entry pressure’ that is used to indicate flow barriers and flow paths during buoyant flow. A previous study (Saadatpoor, 2012) found that issues exist in the criterion method: unknown physical critical capillary entry pressures and boundary barriers. This work addresses the two issues. It is shown that the criterion method gives a close upper bound estimation of local capillary trap volume capacities. Several fine-scale geostatistical realizations of capillary entry pressure fields are considered, and the effects of reservoir heterogeneity, system sizes, aspect ratios, and boundary types are examined. The results from the GC are also strictly interpreted through invoking a simple counting argument. The overall work enhances our mechanistic understanding of the geological controls of local capillary traps.

Effect of interlayer heterogeneity on multi-seam coalbed methane production: A numerical study using a gray lattice Boltzmann model

Multi-seam or multi-zone commingled production of coalbed methane (CBM) in a single wellbore would substantially increase the cumulative gas production. In general, CBM reservoir is highly heterogeneous and anisotropic. To understand the impact of interlayer heterogeneity on commingled production, numerical simulations for two-seam commingled production of CBM were carried out using a gray lattice Boltzmann model. The heterogeneous permeability fields were modeled using the Gaussian distribution function. Based on the interpolation-supplemented lattice Boltzmann method (ISLBM), the non-uniform mesh grid was used in the simulations to achieve a higher computational efficiency. The pressure and velocity distributions of multi-seam commingled production with different heterogeneity coefficient were obtained. The results show that as the coefficient of permeability heterogeneity increased, the sweep region of pressure drop and flow velocity decrease significantly in the heterogeneous seam. By introducing the coefficient B, which represents the level of production decline caused by interlayer heterogeneity, we note that the gas production appears most sensitive in the case of low heterogeneity coefficient s. When the value of s is fixed, for a greater reservoir average permeability Kmp, the effect of reservoir heterogeneity on CBM production is more significant. This work presents a simplified reservoir model that can be useful for production dynamic analysis, production system optimization and productivity prediction of heterogeneous reservoirs in multi-seam commingled production.

Application of four-dimensional monitoring to understand reservoir heterogeneity controls on fluid flow during the development of a submarine channel system

The effects of reservoir heterogeneity on the development of submarine channel fields are still poorly understood because of lack of direct evidence for fluid flow. This study uses integrated well logs and three-dimensional seismic data from the Niger Delta Basin to characterize the previously undocumented spatial distribution of shale units and permeability contrasts within a submarine channel system. Combining these data with four-dimensional (4-D) seismic data facilitates the exploration of the controls of reservoir heterogeneity on fluid flow during development. The results show that the studied submarine channel system consists of multiple vertically stacked channel complex sets (CCSs) from CCS1 (oldest) to CCS5 (youngest), which are separated from each other by continuous shale barriers. The CCS2–CCS4, which are located in the stratigraphic middle of the channel system, are the main development layers because of their higher permeabilities and lower permeability contrasts. The 4-D seismic responses validate that the presence of shale barriers between vertically adjacent CCSs can hinder the flow of fluids between CCSs. Fluid flow between vertically adjacent CCSs barely occurs except in localized erosional locations where the sand fills of different CCSs are vertically connected. Each CCS consists of multiple individual channels, which can be separated by inclined shale baffles if they laterally migrate in one direction. As the 4-D seismic responses demonstrate, such inclined shale baffles can hinder fluid flow between adjacent individual channels and help to form multiple narrow flow paths in map view. The absence of inclined shale baffles also produces prominent permeability contrasts within each CCS, which are characterized by relatively high–permeability zones that are parallel to the channel axis. Comparison of this permeability distribution and the 4-D seismic responses shows that injected water preferentially sweeps along relatively high–permeability zones, which can help to form single wide flow paths with higher sweep efficiency or single narrow flow paths with lower sweep efficiency.

Reservoir sensitivity analysis for heterogeneity and anisotropy effects quantification through the cyclic CO2-Assisted Gravity Drainage EOR process – A case study from South Rumaila oil field

The effects of reservoir heterogeneity and anisotropy were quantified through the cyclic CO2-Assisted Gravity Drainage (GAGD) process performance in a heterogeneous multi-layering sandstone reservoir. First, an integrating workflow of multiple-point geostatistics (MPS) and Sequential Gaussian Simulation (SGSIM) was adopted for the lithological and petrophysical modeling to capture the fluvial depositional environment and preserve the reservoir heterogeneity, respectively. Next, sensitivity analysis was conducted through compositional reservoir simulation and Design of Experiments (DoE) to eliminate the non-influencing petrophysical parameters on the GAGD process performance. Then, heterogeneity and anisotropy effects were quantified with respect to reservoir permeability and anisotropy ratio, respectively. The effects was attained by generating and incorporating multiple reservoir stochastic images (realizations) that capture the entire geological uncertainty space into the reservoir flow simulation. Based on the reservoir flow responses, it was concluded that the impact of permeability anisotropy on the GAGD process is higher than that of heterogeneity, because the main concept of GAGD process considers vertical fluid movements from the top-layer injection wells to the horizontal producers.

Effect of reservoir heterogeneity on the vertical migration of hydraulic fractures

The effect of different types of vertical reservoir heterogeneities on fracture propagation was systematically investigated. A fully 3-D, poroelastic model that does not prescribe the crack propagation path is used to estimate the fracture geometry in vertically heterogeneous rocks. Complex fracture trajectories are shown to occur and this limits fracture height growth. It is shown that the presence of bedding planes, layer interfaces and even smaller scale heterogeneities can lead to fracture turning, kinking or branching. The mechanisms that control these characteristic fracture propagation behaviors (“turning”, “kinking”, and “branching”) near the layer interface are explored in detail. In layered systems, the mechanical property contrast between layers, the dip angle, the stress contrast and the mechanical properties of the layer interface all play an important role in controlling the fracture trajectory. Conditions under which each type of behavior is expected to occur are clearly delineated.

Effects of reservoir heterogeneity on scaling of effective mass transfer coefficient for solute transport

Modeling transport process at large scale requires proper scale-up of subsurface heterogeneity and an understanding of its interaction with the underlying transport mechanisms. A technique based on volume averaging is applied to quantitatively assess the scaling characteristics of effective mass transfer coefficient in heterogeneous reservoir models. The effective mass transfer coefficient represents the combined contribution from diffusion and dispersion to the transport of non-reactive solute particles within a fluid phase. Although treatment of transport problems with the volume averaging technique has been published in the past, application to geological systems exhibiting realistic spatial variability remains a challenge. Previously, the authors developed a new procedure where results from a fine-scale numerical flow simulation reflecting the full physics of the transport process albeit over a sub-volume of the reservoir are integrated with the volume averaging technique to provide effective description of transport properties. The procedure is extended such that spatial averaging is performed at the local-heterogeneity scale.In this paper, the transport of a passive (non-reactive) solute is simulated on multiple reservoir models exhibiting different patterns of heterogeneities, and the scaling behavior of effective mass transfer coefficient (Keff) is examined and compared. One such set of models exhibit power-law (fractal) characteristics, and the variability of dispersion and Keff with scale is in good agreement with analytical expressions described in the literature.This work offers an insight into the impacts of heterogeneity on the scaling of effective transport parameters. A key finding is that spatial heterogeneity models with similar univariate and bivariate statistics may exhibit different scaling characteristics because of the influence of higher order statistics. More mixing is observed in the channelized models with higher-order continuity. It reinforces the notion that the flow response is influenced by the higher-order statistical description of heterogeneity. An important implication is that when scaling-up transport response from lab-scale results to the field scale, it is necessary to account for the scale-up of heterogeneity. Since the characteristics of higher-order multivariate distributions and large-scale heterogeneity are typically not captured in small-scale experiments, a reservoir modeling framework that captures the uncertainty in heterogeneity description should be adopted.

Geological uncertainty and effects of depositional sequence on improved oil recovery processes

Several emerging improved oil recovery (IOR) techniques have been proposed in the past decades with promising results. However, a systematic study of reservoir heterogeneity on these advanced processes has not yet been presented. This paper provides one of the first comparative evaluations of the effects of reservoir heterogeneity on various IOR processes from the conventional methods (waterflooding, CO2 flooding) to the emerging recovery technologies (Low-Salinity Waterflooding and CO2 Low-Salinity WAG) for wider and more successful implementation of these projects. Since weakness exists in the current simple and unrealistic models, detailed geostatistic models are employed to provide a more realistic and unbiased evaluation of reservoir heterogeneity. A new modeling approach that involves the integration of geological software, a reservoir simulator and a robust optimizer in a closed loop for generating multiple geologically driven realizations and uncertainty assessment of different recovery processes is introduced. Then a series of numerical simulations is conducted to investigate the influences of FU and CU sequences on oil recovery. Finally, the uncertainty range of reservoir heterogeneity is thoroughly evaluated using a large number of geological realizations with significant differences on porosity and permeability distributions. The effect of the K v /K h (aspect) ratio is also addressed in this study. The simulation results indicate that the depositional sequence has a dominant effect on oil recovery in all recovery processes. The CU distribution demonstrates superior performance over the FU distribution.

Inflow performance relationships for layered solution-gas drive reservoir

Inflow performance relationship (IPR) is a very important tool to forecast well performance. Existing IPR models are idealistic since they are developed for homogeneous reservoirs; therefore, they are inappropriate for layered systems. Consequently, there is a need for IPR models that efficiently describe layered reservoir performance. This study investigates the effects of reservoir heterogeneity on IPR for layered solution-gas drive reservoirs. Multiphase flow in both two and multilayer reservoirs was simulated. Both fluid cross flow and no fluid cross flow among layers were considered. A stochastic simulation algorithm was used to generate various permeability realisations among layers. Three geostatistical models using uniform, Gaussian, and bimodal probability distributions were used to grasp optimum match between real reservoir behaviour and simulated data. The generated data were scrutinised to develop two accurate IPR equations. The first equation describes the well behaviour under current flowing conditions, whereas the second equation can be used to forecast future well performance.

Investigating the effect of heterogeneity on infill wells

In recent years, improving oil recovery (IOR) has become an important subject for the petroleum industry. One IOR method is infill drilling, which improves hydrocarbon recovery from virgin zones of the reservoir. Determining the appropriate location for the infill wells is very challenging and greatly depends on different factors such as the reservoir heterogeneity. This study aims to investigate the effect of reservoir heterogeneity on the location of infill well. In order to characterize the effect of heterogeneity on infill well locations, some geostatistical methods, e.g., sequential gaussian simulation, have been applied to generate various heterogeneity models. In particular, different correlation ranges (R) were used to observe the effect of heterogeneity. Results revealed that an increase in correlation ranges will lead to (1) a higher field oil production total, and (2) a faster expansion of the drainage radius which consequently reduced the need for infill wells. The results of this study will help engineers to appropriately design infill drilling schemes.