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This paper proposes a novel intelligent method for defining and solving the reservoir performance prediction problem within a manifold space, fully considering geological uncertainty and the characteristics of reservoirs performance under time-varying well control conditions, creating a surrogate model for reservoir performance prediction based on Conditional Evolutionary Generative Adversarial Networks (CE-GAN). The CE-GAN leverages conditional evolution in the feature space to direct the evolution of the generative network in previously uncontrollable directions, and transforms the problem of reservoir performance prediction into an image evolution problem based on permeability distribution, initial reservoir performance and time-varying well control, thereby enabling fast and accurate reservoir performance prediction under time-varying well control conditions. The experimental results in basic (egg model) and actual water-flooding reservoirs show that the model predictions align well with numerical simulations. In the basic reservoir model validation, the median relative residuals for pressure and oil saturation are 0.5% and 9.0%, respectively. In the actual reservoir model validation, the median relative residuals for both pressure and oil saturation are 4.0%. Regarding time efficiency, the surrogate model after training achieves approximately 160-fold and 280-fold increases in computational speed for the basic and actual reservoir models, respectively, compared with traditional numerical simulations. The reservoir performance prediction surrogate model based on the CE-GAN can effectively enhance the efficiency of production optimization. [ABSTRACT FROM AUTHOR]

This paper proposes a novel intelligent method for defining and solving the reservoir performance prediction problem within a manifold space, fully considering geological uncertainty and the characteristics of reservoirs performance under time-varying well control conditions, creating a surrogate model for reservoir performance prediction based on Conditional Evolutionary Generative Adversarial Networks (CE-GAN). The CE-GAN leverages conditional evolution in the feature space to direct the evolution of the generative network in previously uncontrollable directions, and transforms the problem of reservoir performance prediction into an image evolution problem based on permeability distribution, initial reservoir performance and time-varying well control, thereby enabling fast and accurate reservoir performance prediction under time-varying well control conditions. The experimental results in basic (egg model) and actual water-flooding reservoirs show that the model predictions align well with numerical simulations. In the basic reservoir model validation, the median relative residuals for pressure and oil saturation are 0.5% and 9.0%, respectively. In the actual reservoir model validation, the median relative residuals for both pressure and oil saturation are 4.0%. Regarding time efficiency, the surrogate model after training achieves approximately 160-fold and 280-fold increases in computational speed for the basic and actual reservoir models, respectively, compared with traditional numerical simulations. The reservoir performance prediction surrogate model based on the CE-GAN can effectively enhance the efficiency of production optimization.

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Selecting appropriate climate change scenarios is crucial, as it influences the outcomes of climate change impact studies. Several storylines could be used to investigate the sensitivity of water resource schemes to weather variability and improve policymakers' adaptation strategies. This study proposes a comprehensive and generic methodology for assessing the future climate change impact on semi-arid and arid zones at the basin scale by comparing delta perturbation scenarios to the outcomes of seven collections of GCMs (general circulation models). The findings indicate that the two scenarios predicted nearly identical declines in average reservoir discharges over a monthly timescale. Consequently, their maximum values are almost similar. The projected decrease in the streamflow for the period 2080–2099 is approximately 48%—the same as the ratio from the delta perturbation scenario of Future16 (a 30% precipitation decrease and a 30% potential evapotranspiration increase). Furthermore, delta perturbation scenarios allow the impacts of model sensitivity to climate change to be clearly identified in relation to GCM scenarios. Delta perturbation scenarios allow for an extensive collection of possible climate changes at the regional scale. In addition, delta perturbation scenarios are simpler to create and use; therefore, they might complement GCM scenarios. [ABSTRACT FROM AUTHOR]

Selecting appropriate climate change scenarios is crucial, as it influences the outcomes of climate change impact studies. Several storylines could be used to investigate the sensitivity of water resource schemes to weather variability and improve policymakers’ adaptation strategies. This study proposes a comprehensive and generic methodology for assessing the future climate change impact on semi-arid and arid zones at the basin scale by comparing delta perturbation scenarios to the outcomes of seven collections of GCMs (general circulation models). The findings indicate that the two scenarios predicted nearly identical declines in average reservoir discharges over a monthly timescale. Consequently, their maximum values are almost similar. The projected decrease in the streamflow for the period 2080–2099 is approximately 48%—the same as the ratio from the delta perturbation scenario of Future16 (a 30% precipitation decrease and a 30% potential evapotranspiration increase). Furthermore, delta perturbation scenarios allow the impacts of model sensitivity to climate change to be clearly identified in relation to GCM scenarios. Delta perturbation scenarios allow for an extensive collection of possible climate changes at the regional scale. In addition, delta perturbation scenarios are simpler to create and use; therefore, they might complement GCM scenarios.

In order to deepen the understanding of the diagenetic environment, evolution mode and pore development mechanism of the reservoir in the Second Member of Shahejie Formation of Qibei Slope, the characteristics of alkaline environmental diagenesis, diagenetic evolution mode, alkaline environmental genesis mechanism and its in- fluence on pore development of the dense sandstone reservoir in the Second Member of Shahejie Formation were studied by means of rock (cast) thin section, scanning electron microscopy and X-ray diffraction analysis. The results show that there are various alkaline environment diagenesis phenomena in the reservoir, such as quartz dissolution, multi-phase carbonate mineral cementation and metasomatism, anhydrite metasomatism and alkaline clay mineral assemblage; the current reservoir diagenctic stage is in the mesogenetic A2 sub-stage, and the diagenetic environment has experienced alkaline-acidic-alkaline changes during the whole diagenetic evolution; in the early diagenetic stage, the formation of the alkaline diagenetic environment was closely related to the saltwater lake basin environment in the same sedimentary stage. In the mesogenetic A2 sub-stage, due to the enrichment of metal cations, the acidic water source was reduced and heavily depleted, resulting in the increase of the pH value of the pore water medium and a return to the alkaline diagenetic environment; the multi-phase carbonate cement formed in the alkaline environment filled the pores in large quantities, which significantly reduces the reservoir space, and at the same time, the early alkaline fluid medium in the reservoir also suppressed the dissolution modification intensity of the acidic fluid to the reservoir, but the quartz dissolution in the alkaline environment formed a large number of sec- ondary pores, which is the main mechanism of pore development in the reservoir within the study area. The research results are of guiding significance for predicting the distribution of high-quality reservoirs in the study area. [ABSTRACT FROM AUTHOR]

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A novel challenge faced by water scientists and water managers today is the efficient management of the available water resources for meeting crucial demands such as drinking water supply, irrigation and hydro-power generation. Optimal operation of reservoirs is of paramount importance for better management of scarce water resources under competing multiple demands such as irrigation, water supply etc., with decreasing reliability of these systems under climate change. This study compares six different state-of-the-art modeling techniques namely; Deterministic Dynamic Programming (DDP), Stochastic Dynamic Programming (SDP), Implicit Stochastic Optimization (ISO), Fitted Q-Iteration (FQI), Sampling Stochastic Dynamic Programming (SSDP), and Model Predictive Control (MPC), in developing pareto-optimal reservoir operation solutions considering two competing operational objectives of irrigation and flood control for the Pong reservoir located in Beas River, India. Set of pareto-optimal (approximate) solutions were derived using the above-mentioned six methods based on different convex combinations of the two objectives and finally the performances of the resulting sets of pareto-optimal solutions were compared. Additionally, key reservoir performance indices including resilience, reliability, vulnerability and sustainability were estimated to study the performance of the current operation of the reservoir. Modeling results indicate that the optimal-operational solution developed by DDP attains the best performance followed by the MPC and FQI. The performance of the Pong reservoir operation assessed by comparing different performance indices suggests that there is high vulnerability (~ 0.65) and low resilience (~ 0.10) in current operations and the development of pareto-optimal operation solutions using multiple state-of-the-art modeling techniques might be crucial for making better reservoir operation decisions. [ABSTRACT FROM AUTHOR]

• The Volumetric Idleness Coefficient allows to identify the less idle reservoir. • The Volumetric Overflow Coefficient allows to identify minimum overflow scenarios. • The optimal reservoir volume can be associated with minimum values of VOC or VIC. In Brazil, the existing regional disparity in water availability makes it essential to search for alternative solutions that guarantee the supply complies with water quality parameters, affordable cost and adaptation to local conditions and needs. Rainwater may satisfy these requirements. The existence, however, of numerous methods for sizing the reservoir of the system adds some subjectivity to the calculation of the storage volume and can lead to the determination of a storage value that does not meet the project's needs. In this context, this work aims to propose two coefficients, the Volumetric Idleness Coefficient (VIC) and the Volumetric Overflow Coefficient (VOC), which can be used as criteria for determining optimal volumes of reservoirs for rainwater storage. To this end, we considered three reservoir sizing methodologies, already existing in the literature, in different scenarios of catchment area and demand, with data from daily rainfall series of 37 years throughout the Brazilian territory. Additionally, an algorithm in Python was developed to obtain the values of these coefficients for the selected reservoir sizing methods for any point in Brazil, considering different scenarios of catchment area and demand. Results showed that the rainfall characteristics influence the values obtained for VIC and VOC, especially when the reservoirs are sized by a method that considers a water balance. Furthermore, an increase in demand in the catchment area causes a decrease in the values of both coefficients. Both coefficients presented in this article can be applied as reservoir sizing criteria through the comparative analysis between different sizing methods within a scenario since the method that allows a minimum coefficient is associated with an optimal reservoir volume, either for the project that aims to maximize the use of the useful storage volume (VIC) or maximize the use of the volume of water captured by the system (VOC). [ABSTRACT FROM AUTHOR]

The Jiyuan oil field is a tight sandstone reservoir, and water injection does not effectively enhance the oil recovery. The microscopic seepage characteristics of water flooding are studied through physical and streamline simulation experiments. The results indicate that the piston-type displacement efficiency varies between 60% and 80%, and the nonpiston-type displacement efficiency reaches approximately 40%. The length of the horizontal section imposes the greatest influence on reservoir production, followed by the fracture length and the number of fracture segments, whereas the fracture conductivity impacts reservoir production the least. When the horizontal section length is 1,500 m, and the fracture length is 1,100 m, 5 fracture segments and 10 horizontal well clusters are adopted, and the conductivity of the artificial fractures reaches 200 um2×cm , while the oil field production efficiency reaches its maximum value. The preceding research results were applied in the Jiyuan oil field, and the results reveal that the initial well production increased by 47.06%, the decline rate decreased by 9.96%, and the well output increased by 19.1% during the stable production period. This research yields a reference significance for the efficient development of similar reservoirs. [ABSTRACT FROM AUTHOR]

Abstract The main objective of this paper is to understand the impact of the fractal characteristics of fractured reservoirs on their pressure behavior, flow rate decline, and productivity index. The paper proposes a new methodology for developing several analytical models for describing the wellbore pressure distribution and the flow rate decline trend. The proposed models consider including the fractal characteristics such as the mass fractal dimension, conductivity index of anomalous diffusion flow mechanism, fractal-network parameters, fractional-derivative order, and matrix/fracture-interaction index as well as dual-porosity media characteristics such as the storativity and interporosity flow coefficient in the analytical models of the pressure, rate, and productivity index. The study has found that: (1) Some of the fractal characteristics have a significant impact on reservoir performance, while others may not have a significant impact. (2) Fractal reservoirs exhibit better performance than the standard geometry reservoirs of single and dual-porosity media.

Down-flush hydrodynamic movement of fluids at at transitional zones towards areas with low pressure gradients have been reported to directly influence the accurate prediction of petroleum reservoir’s production performances over time. Fluctuations in the fluid-fluid interactions and pressure changes around the reference line was the major cause for the discrepancy. In this research, a sensitivity study on the influence of hydrodynamic tilt factor h to oil, water and gas production was carried-out by means of the commercial software Eclipse Black oil simulator using the openSource Norne field data. The constant h is a function of the corrected shut-in pressure, fluid specific gravity at contact base-lines, pressure at the reference elevation and at the oil-water contact. The error in the contact depth was captured using the difference between the initial and calculated true vertical depths of the fluid’s contact zones. The obtained information was fed into the simulator to model the process dynamics. Findings revealed that the error margin for the first case hA (gas-oil contact) was insignificant. However, a mean deviation in the reservoir’s production predictions of atleast 8% for approximately a 6.5% change in the interacting fluids density was attained in-contrast to the base case.

The main objective of this paper is to understand the impact of the fractal characteristics of fractured reservoirs on their pressure behavior, flow rate decline, and productivity index. The paper proposes a new methodology for developing several analytical models for describing the wellbore pressure distribution and the flow rate decline trend. The proposed models consider including the fractal characteristics such as the mass fractal dimension, conductivity index of anomalous diffusion flow mechanism, fractal-network parameters, fractional-derivative order, and matrix/fracture-interaction index as well as dual-porosity media characteristics such as the storativity and interporosity flow coefficient in the analytical models of the pressure, rate, and productivity index. The study has found that: (1) Some of the fractal characteristics have a significant impact on reservoir performance, while others may not have a significant impact. (2) Fractal reservoirs exhibit better performance than the standard geometry reservoirs of single and dual-porosity media. [ABSTRACT FROM AUTHOR]

Reevaluation of the reliability of reservoirs in meeting operating objectives is needed as the landscape and operational priorities change. This study examined the individual and collective changes in reservoir performance at the 13 flood regulation projects within the Willamette River Basin (WRB) in Oregon. By applying a scenario-based analysis, derived as part of a broader collaborative modeling project, operational performance was evaluated in response to climate and operational change scenarios. Results indicated that, for the climate scenarios analyzed, primary operating objectives of flood risk reduction and meeting summer biological opinion (BiOp) flow targets were unlikely to be affected. Modest reductions in the ability to fully refill the reservoirs and to meet spring BiOp flow targets were found, particularly under the more severe warming scenario. However, refilling the reservoirs 2 weeks earlier was effective in reducing the storage deficit introduced by climate change without compromising the ability to meet other operational objectives. Drawdown scenarios for maintenance of aging infrastructure had minimal effect at the system scale. While the model was limited by the number of climate scenarios represented and in its ability to represent the full range of variability of this large basin, the results cumulatively suggested that the hydrologic changes associated with the range of climate change examined were not likely to substantially reduce the reliability of the Willamette Project in meeting operational objectives. Where potential deficiencies emerged, they could largely be mitigated through simple operational changes. Instead, it is likely that changes in the sociopolitical landscape (e.g., water rights allocations) and management of water quality (e.g., temperature, harmful algal blooms) will be as or more important than hydrologic changes in reducing reservoir performance in meeting operational objectives. [ABSTRACT FROM AUTHOR]

Climate change and population growth have influenced social and physical water scarcity in many regions. Accordingly, the future performance of water storage reservoirs, as one of the fundamental elements in the water resource management, are anticipated to be affected by climate change. This study reports on a framework that can model Reliability-Resiliency-Vulnerability (RRV) measures of water reservoirs in the context of climate change. The framework first develops a hydrological model of a reservoir system using its historical data. The model is then optimised to minimise the water deficit and flooding around the catchment area of the reservoir. The resulting optimal policies are simulated back to the model considering the GCMs. Finally, RRV indices are calculated. RRV indices are effective measures for defining the performance of reservoir systems. Reliability is defined as the probability of the failure of the system, Resiliency is defined as the time needed for the system to go back to its satisfactory state once it entered the failure state, and Vulnerability is defined as the "magnitude of the failure" of a system. The proposed framework has been applied to a reservoir system located in the south-west of Iran on the Dez river. The results show climate change may increase the reliability and resiliency of the system under study while increasing its vulnerability. Therefore, the output of this framework can also provide supplementary information to authorities and decision-makers to inform future water management and planning policies. [ABSTRACT FROM AUTHOR]

The features of bad flow unit continuity and multiple layers emphesize the importance of a well pattern design for the development of a fluvial-delta reservoir. It is proposed a method to predict well pattern connectivity (WPC) based on the exploration and evaluation of wells. Moreover, the method helps evaluate the risk of well placement. This study initially establishes the parameters for characterizing the lateral and vertical flow unit distributions. Then, extensive statistics on the mature oil-field sands of synthetic geological models are obtained to generate the prediction model of WPC which will reveal the correlation among WPC, flow unit distribution, and well spacing (WS). Finally, a case study is conducted to validate the proposed method for predicting WPC. The procedure of the method is comprised of two steps. The first step is to calculate the parameters which characterize the vertical sand body distribution of the target formation by using the well drilling and logging information. The second step is to integrate the calculated parameters and designed WS into the proposed formula to forecast WPC. The new method of WPC prediction has the advantage of integrating the static and dynamic information of similar mature oil fields with each other. By utilizing the model, making an important decision on well pattern design and a reservoir production forecast in the newly discovered continental fluvial-delta reservoir would be reasonable.

Abstract Accurate fluid flow simulation in geologically complex reservoirs is of particular importance in construction of reservoir simulators. General approaches in naturally fractured reservoir simulation involve use of unstructured grids or a structured grid coupled with locally unstructured grids and discrete fracture models. These methods suffer from drawbacks such as lack of flexibility and of ease of updating. In this study, I combined fracture modeling by elastic gridding which improves flexibility, especially in complex reservoirs. The proposed model revises conventional modeling fractures by hard rigid planes that do not change through production. This is a dubious assumption, especially in reservoirs with a high production rate in the beginning. The proposed elastic fracture modeling considers changes in fracture properties, shape and aperture through the simulation. This strategy is only reliable for naturally fractured reservoirs with high fracture permeability and less permeable matrix and parallel fractures with less cross-connections. Comparison of elastic fracture modeling results with conventional modeling showed that these assumptions will cause production pressure to enlarge fracture apertures and change fracture shapes, which consequently results in lower production compared with what was previously assumed. It is concluded that an elastic gridded model could better simulate reservoir performance.

Abstract This paper focuses on studying pressure behavior, flow regimes, and productivity index of oil and gas reservoirs depleted by horizontal wells with a fishbone type completion technology. The main objective is introducing an integrated approach for the favorable configuration and distribution of multilateral horizontal wells extending in porous media at arbitrary directions and arbitrary permeability trajectories. The study aims to demonstrate the advantages and disadvantages of fishbone completion in terms of transient and pseudo-steady state productivity index considering single phase flow in the porous media. It is also an attempt to propose new analytical models for the expected flow regimes and new practical solutions for estimating stabilized productivity index for different scenarios of fishbone completion. In this study, pressure distribution in the porous media is described by several analytical models considering different reservoir geometries and different multilateral horizontal wellbore configurations. These models are solved for single and dual porous media where naturally induced fractures exist. Lateral and spatial permeability are considered in these models as well as non-Darcy flow impact close to the vicinity of the wellbores in gas reservoirs. The solutions of these models are used to generate analytical models for the flow regimes that can be observed during the entire production life. Transient and stabilized productivity indices are quantified for the case of constant production rate using the observed pressure responses of fishbone type horizontal wells. The starting time of pseudo-steady state and the stabilized pseudo-steady state productivity index are used to assess the optimal configuration for fishbone completion. The observations are summarized in: 1) Pressure behavior, flow regimes, and productivity index of fishbone type horizontal wells are impacted by main wellbore and laterals distribution, however, laterals distribution in both sides of the main wellbore may not have an impact in isotropic formations. 2) Azimuth and vertical deviation angles from the main horizontal wellbore and lateral and spatial anisotropies have similar impacts because they change hypothetically the lateral length. 3) The impact of azimuth angle might be maximized by the lateral anisotropy while spatial anisotropy could maximize the impact of vertical deviation angle. 4) The conjunction points of the laterals and the main wellbore may not have a significant impact. 5) Productivity indices of fishbone type horizontal wellbores during early and late production times are less than the ones obtained by single horizontal well, however, almost identical indices are seen at intermediate production time when linear flow regime is observed. 6) The starting time of pseudo-steady state flow is controlled by the main wellbore length more than the laterals' characteristics unless these laterals extend to reservoir boundaries. The conclusions summed up from the results of this study are: 1) Eventhough fishbone type completion could be significant solution for a lot of operation problems of long horizontal wellbore such as excessive pressure drop and wellbore instability, it is not necessary delivering optimum reservoir performance. 2) Flow regimes and flow patterns (transient or pseudo-steady state) are affected by the characteristics and distributions of the main wellbore and laterals in the porous media. Highlights • Pressure behavior, flow regimes, and productivity index of fishbone type horizontal wells are studied in this paper. • The impact of main wellbore length and lateral lengths and numbers are examined. • Impacts of azimuth and vertical angles from horizontal wellbores and lateral and spatial anisotropies are investigated. • Impacts of Darcy and non-Darcy flow are studied as well as type of porous media whether single or dual porous media. • Pseudo-steady state productivity index is determined for different reservoir configurations and wellbore types. [ABSTRACT FROM AUTHOR]

Copyright of Natural Gas Geoscience is the property of Natural Gas Geoscience and its content may not be copied or emailed to multiple sites or posted to a listserv without the copyright holder's express written permission. However, users may print, download, or email articles for individual use. This abstract may be abridged. No warranty is given about the accuracy of the copy. Users should refer to the original published version of the material for the full abstract. (Copyright applies to all Abstracts.)

Abstract This paper introduces new integrated approaches for estimating pseudo-steady state productivity index (PI) and shape factor of oil and gas reservoirs drained by horizontal wells and dominated by multiphase flow conditions. These approaches couple PVT data, relative permeability curves, and pressure distribution models during pseudo-steady state flow (PSS). The objective is eliminating the uncertainties of applying single phase flow models and substantially comprising the realistic parameters that govern multiphase flow conditions. The importance of this study is represented by introducing the impact of multiphase flow (Gas, Oil, Water) to the productivity index and inflow performance relationship of reservoirs depleted by horizontal wellbores. This study is conducted throughout three tasks. The first includes reviewing currently used techniques for calculating pseudo-steady state PI and shape factor of bounded oil and gas reservoirs assuming single phase flow is the dominant flow pattern in the porous media. The second introduces new deterministic models for reservoir mobility and compressibility and new multiphase flow pressure function [ f (P) m p ]. While the third focuses on calculating PI and shape factor of reservoirs depleted by horizontal wellbores and predicting inflow performance relationship (IPR) considering multiphase flow conditions. The outcomes of this study can be summarized as: 1) Developing deterministic models by multi-regression analysis for reservoir mobility and compressibility using PVT data and relative permeability curves. 2) Generating multiphase flow reservoir pressure function [ f (P) m p ] that introduces the impact of multiphase flow conditions to PI model. 3) Applying the new approaches for calculating multiphase flow PI and shape factor and thereafter generating multiphase flow IPR. The study has pointed out: 1) The fact that the PI of constant Sandface flow rate is greater than constant wellbore pressure is confirmed for single and multiphase flow conditions. 2) PI and shape factor are time invariant at late production time and depends only on reservoir geometry and wellbore type. 3) PI of multiphase flow is less than the index of single phase flow while shape factor exhibits higher value for multiphase flow compared to the one for single phase flow. 4) Multiphase flow negatively changes the IPR either by increasing the pressure drop or by declining the flow rate. 5) Most of the deterministic models developed in this study show high accuracy (high R-squared value, R 2 ≥ 90 %) for the changes in fluid properties with reservoir pressure. Highlights • Performance integrated approaches for reservoirs drained by horizontal wells and dominated by multiphase flow conditions. • The approaches couple PVT data, relative permeability curves, and pressure distribution models during pseudo-steady state flow. • New deterministic models for reservoir mobility and compressibility and new multiphase flow pressure function. • New technique for predicting inflow performance relationship (IPR) considering multiphase flow conditions. [ABSTRACT FROM AUTHOR]

Abstract The performance of gas-solution-drive reservoirs is difficult to figure out since the treatment of highly nonlinear partial differential equations. In previous works, studies about gas-solution-drive reservoirs are restricted to production data analysis and the calculation of performance is almost lacking. The objective of this paper is to propose a novel application of Boltzmann transformation along with an adaptive-size fourth-order Runge-Kutta to figure out the performance of gas-solution-drive reservoirs in early time from the perspective of a well test analysis. Mathematical models about two-phase flow of one-dimensional linear flow and planar radial flow are established respectively. Through solving the governing equations of constant pressure production, the distribution of pressure and saturation at any time can be obtained easily, and curves of pressure and saturation versus time at a specific position can be also achieved. In addition, profiles of gas and oil flow rate at wellbore in terms of time can be acquired. The effect of bottom-hole pressure (BHP) on pressure, saturation and flow rate in early time is investigated. The results obtained from the newly proposed method are compared with numerical simulation results, and comparison results illustrate that the performance of solution-gas-drive reservoirs can be obtained fast and accurately through the new method. Highlights • Boltzmann transformation method is used to transform partial differential equations into ordinary differential equations. • Solution-gas-drive reservoir performance is calculated, including reservoir pressure, saturation and flow rate at wellbore. • The influences of bottom-hole pressure on reservoir pressure, saturation and flow rate are discussed. [ABSTRACT FROM AUTHOR]

Recent trends suggest that streamflow discharge is diminishing in many rivers of Southern Europe and that interannual variability is increasing. This threatens to aggravate water scarcity problems that periodically arise in this region, because both effects will deteriorate the performance of reservoirs, decreasing their reliable yield. Reservoir storage is the key infrastructure to overcome variability and to enhance water availability in semiarid climates. This paper presents an analysis of the role of reservoir storage in preserving water availability under climate change scenarios. The study is focused on 16 major Southern European basins. Potential water availability was calculated in these basins under current condition and for 35 different climatic projections for the period 2070–2100. The results show that the expected reduction of water availability is comparable to the decrease of the mean annual flow in basins with large storage capacity. For basins with small storage, the expected reduction of water availability is larger than the reduction of mean annual flow. Additionally, a sensitivity analysis was carried out by replicating the analysis assuming variable reservoir volumes from 25% to 175% of current storage. The results show that increasing storage capacity attenuates the reduction of water availability and reduces its uncertainty under climate change projections. This feature would allow water managers to develop suitable policies to mitigate the impacts of climate change, thus enhancing the resilience of the system.

With the rapid development of China's society and economy, relevant industries get good development opportunities, and the demand for oil is increasing. The oil production in the oilfield is increasing day by day. At present, most oilfields gradually enter the middle and late stage of water injection exploitation, which increases the exploitation difficulty and reduces the exploitation amount. In this paper, a comprehensive analysis of waterflooding reservoirs and reservoir performance is made to promote better and faster development of petroleum industry.

Three-dimensional (3D) facies and petrophysical models were generated from previously published data of carbonate strata in the Dam Formation (eastern Saudi Arabia) to quantitatively investigate, describe, understand, model, and predict the permeability anisotropy in tidal flat carbonate on the basis of a sequence stratigraphic framework. The resulting 3D models were used to conduct fluid flow simulations to demonstrate how permeability anisotropy influences the production of hydrocarbons and ultimately affects decisions concerning future drilling in the exploration and development of carbonate reservoirs with tidal flat strata. The constructed 3D facies model consists of four lithofacies associations, two of which are grain-dominated associations and two of which are mud-dominated associations. These lithofacies associations vary spatially in four reservoir zones (zones 1 to 4), which represent two fourth-order sequences in the uppermost part of the Dam Formation. Zones 1 and 3 consist of transgressive parasequences, and zones 2 and 4 consist of the regressive parasequences of these sequences. The 3D porosity and permeability models have a coherent match with the distribution of the lithofacies and the stratigraphic framework of the Dam Formation. The results suggest that the permeability anisotropy in zones 1 and 3 is controlled by the occurrence of the grain-dominated lithofacies associated with tidal flat channels. This lithofacies association overlies the sequence boundaries of sequences 1 and 3, forms reservoir bodies with relatively high permeability values, and is elongated perpendicular to the shoreline of the depositional environment. In contrast, permeability anisotropy in zones 2 and 4 is thought to be controlled by the occurrence of the grain-dominated lithofacies associated with the oolitic shoal. This lithofacies association overlies the maximum flooding surface of sequences 2 and 4, forms reservoir bodies with relatively high permeability values, and is elongated parallel to the shoreline of the depositional environments. Fluid flow simulation results suggest that the trend in hydrocarbon production from the constructed 3D models depends on permeability anisotropy in each reservoir zone. Thus, recognizing trends in permeability anisotropy, which can be predicted using sequence stratigraphy, could help to identify potential areas for future drilling.

This research project gives an insightful glimpse into reservoir simulation using the Material Balance (MBAL) software. The software was used to confirm Stock Tank Oil Initially In-Place (STOIIP) for volumetric analysis. MBAL was used to apply the material balance method, decline curve analysis method, check the aquifer size of the field, and carry out production forecasts. Data from the field was inputted into MBAL and results acquired. These results were used in simulating the reservoir in order to carry out production forecasts. The research showed the impact of MBAL in predicting reservoir performance and carrying out reservoir simulation. The predictions were made based on field data. STOIIP was estimated using non-linear regression with a plot of average reservoir pressure against cumulative oil produced. The history matching tool and the production prediction tool were used to estimate the expected STOIIP, judging from the previous performance of the reservoir and the well. With the use of the analytical tool, the predominant reservoir driving mechanism was determined. This project will focus on the use of reservoir simulation in reservoir engineering and how MBAL can be used as a tool in reservoir simulation. [ABSTRACT FROM AUTHOR]

This paper presents surface movement (uplift and subsidence) analysis around three CO 2 injection wells at In Salah, Algeria. Analysis of surface movement is based on the InSAR data acquired throughout the injection period from 2004 to 2011. This paper focuses on the detail surface deformation patterns for all three injectors throughout the injection period, and eventually correlates such patterns to the CO 2 injection history. Surface uplift has a higher rate in the beginning of the injection period but levels off later on and reaches a final uplift of about 15–22 mm above different wells. We will explore whether surface movement data can reveal signatures of injection regime (i.e. matrix and fracture injections) in the reservoir. Surface movement, for a few selected points at different distances from the wellhead, and the injection pressure are plotted versus time to explore their relationship. Analysis of the plots show that surface subsidence coincide with fracture injection for some points and at certain times whereas it coincides with matrix injection for others. We also tried to map out possible time delay between injection shut-in and surface subsidence. It is learned that quantification of such a delay as well as monitoring the response of surface to fracturing in the reservoir requires high resolution surface movement data. This study shows the potential of satellite survey for monitoring the injection regime and behavior of reservoir and overburden. [ABSTRACT FROM AUTHOR]

Multi-stage hydraulic fracturing is a crucial well completion strategy in unconventional reservoirs to improve hydrocarbon production. Reservoir performance and pressure characterization in multi-stage fracture development considering elastic rock mechanics are not systematically discussed in the literature. This work considers effects of elastic rock mechanics and hydraulic fractures in unconventional reservoir development scenarios using a numerical model with coupled fluid flow and geomechanics. A fully coupled flow and geomechanics model based on finite element method is introduced to analyze shale gas flow and corresponding pressure distribution in unconventional reservoirs. The model is validated with an analytical solution and history matched with field data. Furthermore, effects of rock mechanics, elastic properties, and hydraulic fracture geometry on reservoir performance and pressure distribution are studied using the fully coupled numerical model. Pressure distribution and reservoir performance in terms of production rates of these scenarios are analyzed. It is found that consideration of elastic rock mechanics decreases the hydrocarbon production rates and alters the pressure distribution in the unconventional reservoir. Rock mechanical properties and fracture spacing/length also affect flow rates and pressure. Fracture spacing, fracture length, and Young's modulus have the greatest effect on hydrocarbon production rates. Effects of elastic rock mechanics are most significant at central areas of the fractured region, while such effects are less significant at far ends of the horizontal wellbore. This work incorporates full geomechanics with a flow model to understand reservoir performance and pressure characterization in multi-stage hydraulic fracture development scenarios and quantifies effects of geomechanics and effects of various parameters in unconventional development scenarios. [ABSTRACT FROM AUTHOR]

This paper investigates the impacts of stimulated reservoir volume (SRV) on reservoir performance for unconventional hydraulically fractured formations. It focuses also on the effects of different petrophysical properties of SRV as well as different volume and petrophysical properties of unstimulated part of porous media (USRV). The influences of hydraulic fracture conductivity, fracture assymmetricity, and non-Darcy flow permeability in reservoir pressure profile have been substantially studied in this paper. Stimulated reservoir volume represents the volume of porous media where complex network structures formed from naturally induced fractures, multiple hydraulic fractures, and original matrix. SRV is characterized by an induced or a stimulated matrix permeability which is typically greater than the original matrix permeability. The formations of interest, in this study, are considered having either stimulated reservoir volume only or both stimulated and un-stimulated reservoir volumes and depleted by multiple hydraulic fractures controlled by non-Darcy flow. The impacts of SRV and USRV on pressure distributions, flow regimes, and productivity indices have been studied using multi-linear flow regimes approach. A new analytical model has been proposed in this paper for pressure behavior of a horizontal well intersected by multiple hydraulic fractures assuming symmetrical and asymmetrical stimulated reservoir volumes. This model was developed using multi-linear flow regimes approach with an adjustment for variable SRVs and USRVs. The volume of stimulated part in the reservoir is determined by hydraulic fracture half length, number of fractures and spacing between them, and fracture height. The impact of induced or stimulated matrix permeability in the stimulated reservoir volume and fracture conductivity as well as non-Darcy flow impact on pressure behaviors have also been investigated. Several analytical models for flow regimes, expected to develop during the entire production life of reservoir, were also proposed in this study. A set of type-curves was designed for pseudo-pressure normalized rate and pseudo-pressure normalized cumulative rate with production time. The outcomes of this study can be summarized as: 1) Generating an analytical model that describes pressure behavior in unconventional reservoirs and considers variable SRVs and USRVs. This model includes stimulated matrix permeability, non-Darcy flow impact, and hydraulic fracture conductivity. 2) Understanding the impact of asymmetrical stimulated reservoir volumes on reservoir performance. 3) Developing analytical models for different linear flow regimes that could develop during the entire life of reservoir. 4) Comparing the productivity index for different stimulated and un-stimulated reservoir volumes assuming both symmetrical and asymmetrical reservoir volume. The most interesting points in this study are: 1) Productivity index drops significantly for the case of asymmetrical SRVs compared to symmetrical SRVs. 2) The SRV enhances productivity index more than USRV, however, at early production time, there is no impact for both of them on productivity index. 3) The impact of assymmetricity is seen at all production time. 4) Flow regime types are not changed with respect to the assymmetricity. [ABSTRACT FROM AUTHOR]

Application of simulation model HEC-5 to analyze the performance of the DVC Reservoir System (a multipurpose system with a network of five reservoirs and one barrage) on the river Damodar in Eastern India in meeting projected future demand as well as controlling flood for synthetically generated future scenario is addressed here with a view to develop an appropriate strategy for its operation. Thomas-Fiering model (based on Markov autoregressive model) has been adopted for generation of synthetic scenario (monthly streamflow series) and subsequently downscaling of modeled monthly streamflow to daily values was carried out. The performance of the system (analysed on seasonal basis) in terms of 'Performance Indices' (viz., both quantity based reliability and time based reliability, mean daily deficit, average failure period, resilience and maximum vulnerability indices) for the projected scenario with enhanced demand turned out to be poor compared to that for historical scenario. However, judicious adoption of resource enhancement (marginal reallocation of reservoir storage capacity) and demand management strategy (curtailment of projected high water requirements and trading off between demands) was found to be a viable option for improvement of the performance of the reservoir system appreciably [improvement being (1-51 %), (2-35 %), (16-96 %), (25-50 %), (8-36 %) and (12-30 %) for the indices viz., quantity based reliability, time based reliability, mean daily deficit, average failure period, resilience and maximum vulnerability, respectively] compared to that with normal storage and projected demand. Again, 100 % reliability for flood control for current as well as future synthetically generated scenarios was noted. The results from the study would assist concerned authority in successful operation of reservoirs in the context of growing demand and dwindling resource. [ABSTRACT FROM AUTHOR]

The review of a reservoir performance helps to identify the basic and unique problems plaguing a reservoir which is ought to be resolved before any reasonable simulation and consequent development. This study investigates the application of reservoir performance review and diagnostics on Nok in the Niger Delta to serve as a prerequisite for its development. The Nok reservoir is producing at a rate of 3000stb/day for all wells. Well LU1 and well LU2 were discovered to have excessive water production; having a high water cut of 71.5% and 96.6% for well LU1 and well LU2 respectively. From the review, it was discovered that the causes of the high water cut during oil production from the two wells using diagnostic plots of the Water Oil Ratio (WOR) and Water Oil Ratio Derivative (WOR') versus time were water coning at the early stage of production and channeling at the later stage. Re-perforation at a shallower depth was therefore considered as a go forward plan for Nok reservoir which showed a 0% water cut at a test of re-perforation. [ABSTRACT FROM AUTHOR]

This paper targets the applicability of multi-linear flow regimes approach in gas reservoirs having multiple porous media: matrix, natural fractures, and hydraulic fractures. The approach attempts to understand pressure profiles and flow regimes developed in some of unconventional shale layers that have already been naturally fractured. In this paper, the main focus is given to fluid flow phenomenon from the matrix towards naturally induced fractures and from these fractures to the hydraulic fractures. Studying the impact of matrix, natural fracture and hydraulic fracture parameters on reservoir performance is another objective for this paper. Purposefully, several mathematical models have been developed to investigate transportation phenomenon of reservoir fluid in porous medium. The porous medium is assumed to be finite rectangular reservoir having different configurations. It is divided into two zones; inner porous medium close to the horizontal wellbore where multiple-hydraulic fractures propagate to some distance and outer porous medium where naturally induced fractures exist in the drainage area close to the outer boundary. Reservoir fluids, in the outer zone, are assumed to flow from the matrix to natural fractures and then from natural fractures to the inner zone. In the inner porous medium, fluids flow from matrix to natural fractures in addition to fluids flowing from the outer porous medium. Then all fluids flow by natural fractures to hydraulic fractures and finally from hydraulic fractures to the wellbore. The mathematical models for fluid flow in the two zones of the reservoir have been solved and three main flow regimes have been characterized. For each flow regime, an analytical model is used to describe its pressure profile with time and production performance. Bilinear flow regime, typically observed at early time, refers to simultaneous linear flow inside hydraulic fractures and flow from inner porous medium to the hydraulic fractures while linear flow describes fluids flow from inner zone to hydraulic fractures and late linear or boundary dominated flow regime describes fluids flow from the outer to the inner porous media. The main outcomes of this study are: 1) The ability to characterize reservoirs with triple porous media using multi-linear flow regimes approach. 2) Understanding the impact on pressure distribution of inner porous medium caused by the characteristics of hydraulic fractures such as fracture width and conductivity in addition to hydraulic fracture storativity. 3) Understanding the effect of reservoir configuration, matrix, and natural fractures characteristics on pressure distribution in the outer porous media. 4) Pressure distribution and flow regimes obtained by applying transient flow approach are not similar to those obtained by applying pseudo-steady state flow approach. 5) Characterization of different linear flow regimes, controlled by different parameters, with respect to production time. [ABSTRACT FROM AUTHOR]

An analytical methodology for reservoir characterization was applied in the central and southwestern zones of Los Humeros geothermal field (LHGF). This study involves analysis of temperature, pressure, enthalpy and permeability in wells and their distribution along the area. The wells located in the central western side of the geothermal field are productive, whereas those located at the central-eastern side are non-productive. Through temperature profiles, determined at steady state in the analyzed wells, it was observed that at bottom conditions (approximately 2300 m depth), temperatures vary between 280 and 360 °C. The temperatures are higher at the eastern side of central zone of LHGF. A review of transient pressure tests, laboratory measurements of core samples, and correlation of circulation losses during drilling suggest that permeability of the formation is low. The enthalpy behavior in productive wells shows a tendency of increase in the steam fraction. It was found that productivity behavior has inverse relation with permeability of rock formation. Further, it is observed that an imbalance exists between exploitation and recharge. It is concluded from the results that the wells located at central-eastern area have low permeability and high temperature, which indicates possibility of heat storage. [ABSTRACT FROM AUTHOR]

Accurate fluid flow simulation in geologically complex reservoirs is of particular importance in construction of reservoir simulators. General approaches in naturally fractured reservoir simulation involve use of unstructured grids or a structured grid coupled with locally unstructured grids and discrete fracture models. These methods suffer from drawbacks such as lack of flexibility and of ease of updating. In this study, I combined fracture modeling by elastic gridding which improves flexibility, especially in complex reservoirs. The proposed model revises conventional modeling fractures by hard rigid planes that do not change through production. This is a dubious assumption, especially in reservoirs with a high production rate in the beginning. The proposed elastic fracture modeling considers changes in fracture properties, shape and aperture through the simulation. This strategy is only reliable for naturally fractured reservoirs with high fracture permeability and less permeable matrix and parallel fractures with less cross-connections. Comparison of elastic fracture modeling results with conventional modeling showed that these assumptions will cause production pressure to enlarge fracture apertures and change fracture shapes, which consequently results in lower production compared with what was previously assumed. It is concluded that an elastic gridded model could better simulate reservoir performance. [ABSTRACT FROM AUTHOR]

The CO2 storage reservoir for the Shenhua Carbon Capture and Storage (SHCCS) Demonstration Project in the Ordos Basin in China is known for its low-permeability and low-porosity characteristics. However, injectivity was shown by the in situ monitoring data to be substantially increasing over the years. Previous numerical analyses suggest that such reservoir behavior might be mainly attributed to the permeability heterogeneity of the injection layers. As an intermittent injection procedure was actually practiced in this project, the hysteretic behaviors in relative permeability and capillary pressure in the reservoir could be significant. In this study, the hysteretic processes are investigated for a better understanding of the reservoir performance. History-match is achieved with one order of magnitude lower in the overall permeability of the principal injection layer than the previous simulation. Current calibrated permeability is much closer to seismic measurement and well-log results. Therefore, we believe that the hysteresis effects accompanying the alternation between injection and injection pause might be another important factor accounting for the observed reservoir performance. It is indicated in this study that, by considering the hysteresis effects in the injection-pause sequence, an optimally-designed intermittent injection procedure could greatly improve the injection performance in a saline aquifer with low permeability and low porosity that may seem unfavorable to CO2 storage. © 2016 Society of Chemical Industry and John Wiley & Sons, Ltd. [ABSTRACT FROM AUTHOR]

CO injection is considered as one of the proven EOR methods and is being widely used nowadays in many EOR projects all over the globe. The process of in situ displacement of oil with CO gas is implemented in both miscible and immiscible modes of operation. In some oil reservoirs, CO miscibility will not be attained due to fluid composition characteristics as well as in situ pressure and temperature conditions. Laboratory determination of gas-oil relative permeability curves is usually performed with air, nitrogen, or helium gases, and the results are then implemented for both natural depletion processes (especially in reservoirs with 'solution gas' or 'gas cap' drive mechanisms) and gas injection processes. For the gas injection processes, it is therefore necessary to find out how selection of the gas phase would affect the relative permeability curves when the intention of developing the curves is to use them for immiscible CO displacement. In this study, a reservoir simulator was first used to quantitatively analyze the effect of variation in relative permeability data (due to the use of different gas phases) on production performance of a reservoir. Then, computational analysis was performed on changes in relative permeability curves upon using different gas phases with the aid of pore-scale modeling using statistical methods. To predict gas-oil relative permeability curves, a Shan-Chen-type multi-component multiphase Lattice Boltzmann pore-scale model for two-phase flow in a 2D porous medium was developed. Fully periodic and 'full-way' bounce-back boundary conditions were applied in the model to get infinite domain of fluid with nonslip solid nodes. Incorporation of an external body force was performed by Guo scheme, and the influence of pore structure and capillary number on relative permeability curves was also studied for CO-oil as well as N-oil fluid pairs. The modeled relative permeability curves were then compared with experimental results for both these fluid pairs. [ABSTRACT FROM AUTHOR]

An integrated full-field reservoir simulation study has been performed to determine the reservoir management and production strategies in a mature sandstone reservoir. The reservoir is a candidate for an enhanced oil recovery process or otherwise subject to abandonment. Based on its charateristics, the reservoir was found to be most suited for a surfactant/polymer (SP) flood. The study started with a large data gathering and the building of a full-field three-dimensional geological model. Subsequently, a full field simulation model was built and used to history match the water flood. The history match of the water flood emphasizes the areas with remaining high oil saturations, establishes the initial condition of the reservoir for an SP flood, and generates a forecast of reserves for continued water flood operations. A sector model was constructed from the full field model and then used to study different design parameters to maximize the project profitability from the SP flood. An economic model, based on the estimated recovery, residual oil in-place, oil price, and operating costs, has been implemented in order to optimize the project profitability. The study resulted in the selection of surfactant and polymer concentrations and slug size that yielded the best economic returns when applied in this reservoir. The study shows that, in today’s oil prices, surfactant/polymer flood when applied in this reservoir has increased the ultimate oil recovery and provide a significant financial returns.

The effective hydrocarbon field development requires a well-developed waterflooding strategy with surveillance plan for continuous efficiency monitoring. The modified capacitance resistance model (CRM) is proposed to monitor the efficiency of oil field waterflood. The model outcomes give and understanding of flooding response. Forties field data was used to test and present the waterflood performance based on proposed modified CRM model. [ABSTRACT FROM AUTHOR]

Summary This study employed a Monte-Carlo simulation approach to characterise the uncertainties in climate change induced variations in storage requirements and performance (reliability (time- and volume-based), resilience, vulnerability and sustainability) of surface water reservoirs. Using a calibrated rainfall–runoff (R–R) model, the baseline runoff scenario was first simulated. The R–R inputs (rainfall and temperature) were then perturbed using plausible delta-changes to produce simulated climate change runoff scenarios. Stochastic models of the runoff were developed and used to generate ensembles of both the current and climate-change-perturbed future runoff scenarios. The resulting runoff ensembles were used to force simulation models of the behaviour of the reservoir to produce ‘populations’ of required reservoir storage capacity to meet demands, and the performance. Comparing these parameters between the current and the perturbed provided the population of climate change effects which was then analysed to determine the variability in the impacts. The methodology was applied to the Pong reservoir on the Beas River in northern India. The reservoir serves irrigation and hydropower needs and the hydrology of the catchment is highly influenced by Himalayan seasonal snow and glaciers, and Monsoon rainfall, both of which are predicted to change due to climate change. The results show that required reservoir capacity is highly variable with a coefficient of variation (CV) as high as 0.3 as the future climate becomes drier. Of the performance indices, the vulnerability recorded the highest variability (CV up to 0.5) while the volume-based reliability was the least variable. Such variabilities or uncertainties will, no doubt, complicate the development of climate change adaptation measures; however, knowledge of their sheer magnitudes as obtained in this study will help in the formulation of appropriate policy and technical interventions for sustaining and possibly enhancing water security for irrigation and other uses served by Pong reservoir. [ABSTRACT FROM AUTHOR]

Waterflood or pressure maintenance project is considered one of several methods of enhanced oil recovery, which is widely being used in oil fields. Water injection efficiency analysis is very important for operation future plan and finds out if any opportunity is available to improve project performance. The conventional methods beside nonparametric criteria have been applied in this research in order to evaluate water injection operation. Gini coefficient analysis has been used to illustrate the water injection impact in terms of oil and water production trends over the time of injection operation. [ABSTRACT FROM AUTHOR]

Unique reservoir performance was observed in the Shenhua 100,000 t/year Carbon Capture and Storage (SHCCS) Demonstration Project. Suggested by the geological pre-assessments, hydraulic fracturing and a multi-layer injection procedure were employed to improve the injectivity and reduce the risk of an overpressure. However, in-situ data showed the total injection rate increased after the injection started, while the injection initiation pressure decreased with only a minor pressure build-up development. Additionally, the injectivity of the uppermost injection layer, which was not fractured, grew considerably over the years, making this layer potentially able to meet the target rate by itself. To clarify this unforeseen observation, the reservoir performance was investigated through numerical simulations and comparison against the 2.5-year historical data. The simulation results indicated that permeability heterogeneity of the injection layers might explain the observed reservoir performance. High CO 2 injectivity in the uppermost injection layer could be attributed to its overall permeability being higher than that of other layers, and the considerable injectivity increase over the years could have been caused by the substantial permeability increase along the principal direction of CO 2 migration in this layer. The injectivity improvement caused by hydraulic fracturing was significant in the early time of injection, but it dramatically reduced afterwards. The intermittent injection procedure could effectively reduce the pressure build-up in the reservoir and helped to maintain the injection at the target rate. Based on these assessments, the cumulative injected CO 2 mass could reach 300,000 t in December 2015, but the yearly average injection rate would drop slightly. The predicted cumulative mass could be underestimated because the higher injectivity in 2014 was not accounted for in the calibration, and because the model size could have affected the reservoir performance, as shown by the sensitivity analysis. This research indicated that permeability heterogeneity and the injection procedure could significantly affect the reservoir performance, and should be given consideration in the performance assessment. [ABSTRACT FROM AUTHOR]

Unconventional tight sandstone reservoirs have been developed during recent years and a large number of multi-stage fractured horizontal wells have been drilled to stimulate reservoir performance. However, fluid flow in low permeability porous media no longer obeys Darcy’s law and instead conforms to low-velocity non-Darcy flow. Most commercial numerical simulation software for multi-stage fractured horizontal well development may cause inaccuracy in simulating performance of tight sandstone reservoirs. In this paper, the investigation of existing conditions of low velocity non-Darcy flow for oil flow in irreducible water saturation tight sandstone cores was conducted and discussed through lab-experiments. And existence of low velocity non-Darcy flow was proven. Then, based on the low velocity non-Darcy flow model, the multistage fractured horizontal well numerical simulator was developed and verified. The comprehensive comparison and analysis of the simulation results of Darcy flow and non-Darcy flow were presented including liquid production rate, oil production rate, water cut, reservoir pressure, oil saturation distribution, and dimensionless permeability coefficient. With considering the non-Darcy flow, the fluid flow in reservoir consumes more driving energy and the water flooding efficiency was reduced. Finally, a multistage fractured horizontal well water injection pilot test in Fan-116 block was analyzed to perform the non-Darcy flow numerical study on an actual tight sandstone reservoir. The results show that for the tight sandstone reservoir, the optimal water injection time is when the average reservoir pressure declined to 26.92 MPa based on maximizing the total field oil production in 15 years. This pressure level is close to the hydrostatic pressure and the optimized recovery is 20.51% in the final simulation time. This approach is an initial exploration for the “multi-stage fractured horizontal well development for tight sandstone reservoirs considering non-Darcy flow” and could be applied to other tight oil/gas reservoirs. [ABSTRACT FROM AUTHOR]

Summary Understanding the variability of water supply reservoir yields is central for planning purposes. The basis of this study is an empirical global relationship between reservoir storage capacity, water supply yield and reliability based on a global database of 729 rivers. Monte Carlo simulations reveal that the coefficient of variation of estimates of water supply reservoir yields depend only on the length of streamflows record and the coefficient of variation of the streamflows used to estimate the yield. We compare the results of those Monte Carlo experiments with an analytical uncertainty method First Order Variance Approximation (FOVA). FOVA is shown to produce a general, accurate and useful expression for estimating the coefficient of variation of water supply reservoir yield estimates. We also document how the FOVA analytical model can be used to determine the minimum length of streamflow record required during the design of water supply reservoirs so as to ensure that the yield delivered from reservoir falls within a prespecified margin of error. [ABSTRACT FROM AUTHOR]