Numerical Reservoir Model Research Articles

Feasibility of Waterflooding for a Carbonate Oil Field Through Whole-Field Simulation Studies

The carbonate oil field studied is a currently producing field in U.S., which is named “PSU” field to remain anonymity. Discovered in 1994 with wells on natural flow or through artificial lift, this field had produced 17.8 × 106 bbl of oil to date. It was noticed that gas oil ratio had increased in certain parts and oil production declined with time. This study was undertaken to better understand and optimize management and operation of this field. In this brief, we first reviewed the geology, petrophysical properties, and field production history of PSU field. We then evaluated current production histories with decline curve analysis, developed a numerical reservoir model through matching production and pressure data, then carried out parametric studies to investigate the impact of injection rate, injection locations, and timing of injection, and finally developed optimized improved oil recovery (OIR) methods based on ultimate oil recovery and economics. This brief provides an addition to the list of carbonate fields available in the petroleum literature and also improved understandings of Smackover formation and similar analogous fields. By documenting key features of carbonated oil field performances, we help petroleum engineers, researchers, and students understand carbonate reservoir performances.

Reservoir simulation and optimization of Huff-and-Puff operations in the Bakken Shale

A numerical reservoir model was created to optimize Huff-and-Puff operations in the Bakken Shale. Huff-and-Puff is an enhanced oil recovery method in which a well alternates between injection, soaking, and production. Injecting CO2 (or other gases) into the formation and allowing it to “soak” re-pressurizes the reservoir and improves oil mobility, boosting production from the well. A compositional reservoir simulator (CMG GEM) was used to study various design components of the Huff-and-Puff process in order to identify the parameters with the largest impact on recovery and understand the reservoir’s response to cyclical gas injection. It was found that starting Huff-and-Puff too early in the life of the well diminishes its effectiveness, and that shorter soaking periods are preferable over longer waiting times. Huff-and-Puff works best in reservoirs with highly-conductive natural fracture networks, which allow CO2 to migrate deep into the formation and mix with the reservoir fluids. Doubling the number of hydraulic fractures per stage results in considerably greater gas injection requirements without proportionally larger incremental recovery factors. Incremental recovery from CO2 Huff-and-Puff appears to be insufficient to make the process commercially feasible under current economic conditions. However, re-injecting mixtures of CO2 and produced hydrocarbon gases was shown to be technically and economically viable, and could significantly improve profit margins of Huff-and-Puff operations.

Identification and quantitative description of large pore path in unconsolidated sandstone reservoir during the ultra-high water-cut stage

In unconsolidated sandstone reservoirs associated with fluvial sedimentation, large pore paths are likely to be formed under the long-term scour action of injected water. In this paper, the high-velocity non-Darcy flowing characteristics in large pore paths were analyzed. Based on the identification criteria for high-velocity non-Darcy flow, the identification criteria for large pore paths are established. According to the characteristic parameters of 101 relative permeability curves from the fluvial sedimentary units of the uncompartmentalized oilfields in Shengli oil region, the relation formulae between characteristic parameters of relative permeability curve and permeability are established. Considering the change of reservoir permeability and the relative permeability curve with permeability, a reservoir numerical simulation model is setup. The Ng63+4 development unit of the west seventh block of Gudong Oilfield is taken as a typical reservoir. The distribution position, area and volume of the large pore paths in Ng63+4 development unit are quantitatively described. The results show that the identification criteria of large pore paths which take into consideration the water–oil well spacing, production pressure difference and permeability can be used in the reservoir numerical simulation results to describe the large pore paths.

Forward modelling of seismicity rate changes in georeservoirs with a hybrid geomechanical–statistical prototype model

A key challenge for the development of Enhanced Geothermal Systems (EGS) is to forecast the probability of occurrence of seismic events that have the potential to damage man-made structures. Induced seismicity results from man-made time-dependent stress changes, e.g., due to fluid injection, shut-in and fluid or steam production. To accomplish a classical Probabilistic Seismic Hazard Assessment (PSHA) a catalogue of induced seismicity is required. In addition, PSHA does not return any practical recommendation for how to treat the reservoir geomechanically in order to lower the probability of occurrence of induced seismicity. Thus, we propose to link the simulated stress changes from forward geomechanical numerical reservoir models with the statistical rate-and-state approach of Dieterich (1994). Using this link we translate the modelled time-dependent stress changes into time-dependent changes of seismicity rates. This approach is general and independent of the incorporated geomechanical numerical model used. We exemplify our hybrid model approach using a geomechanical model that describes the stimulation of the well GPK4 at the EGS site in Soultz-sous-Forêts (France) including the shut-in phase. By changing the injection rate in the geomechanical model we generate various synthetic injection scenarios. With these scenarios we can study the effect on the seismicity rate and provide a recommendation for which injection experiment results in the least increase of seismicity rate. The results indicate an explicit coupling between the time-depending stress changes and the induced seismicity rate for each scenario. Even though the hybrid model cannot be used in general to derive absolute values of the rate of induced seismicity a priori (this is only possible if the geomechanical model can be calibrated against observed induced events), it serves as a tool to test the effect of stress changes on the induced seismicity rate. The approach described here is a prototype model illustrating the general workflow. In particular the geomechanical model can be replaced by any other type of reservoir description.

Production optimization using derivative free methods applied to Brugge field case

Recently production optimization has achieved increasing attention in upstream petroleum industry. Here, we evaluate derivative free optimization methods for determination of the optimal production strategy using a numerical reservoir model which was prepared for a comparative study at the SPE Applied Technology Workshop in Brugge, June 2008. The pattern search Hooke–Jeeves, the reflection simplex Nelder–Mead, a new line-search derivative-free and a generalized pattern search methods are applied to the optimization problem. The line-search derivative-free algorithm is developed based on the existing line-search derivative free algorithms in combination with the Hooke–Jeeves pattern search method. The derivative free optimization results are compared with a gradient based sequential quadratic programming algorithm, but we clearly identify some issues limiting the performance of gradient based algorithms. In real applications our optimization problem is facing very costly function evaluations and at the same time one might have limitations in the computational budget. Therefore we are interested in methods that can improve the objective function with few function evaluations. The line-search derivative-free method performs more efficient and better than the other optimization methods. Ranking among the other four methods is somewhat more difficult, except that the Nelder–Mead method clearly has the slowest performance among these methods. We also observed that optimization with sequential quadratic programming had a high risk of getting trapped in a local optimum, which could be explained by properties of the objective function.

Targeted Pressure Management During CO2 Sequestration: Optimization of Well Placement and Brine Extraction

Large-scale pressure increases resulting from carbon dioxide (CO2) injection in the subsurface can potentially impact caprock integrity, induce reactivation of critically stressed faults, and drive CO2 or brine through conductive features into shallow groundwater. Pressure management involving the extraction of native fluids from storage formations can be used to minimize pressure increases while maximizing CO2 storage. However, brine extraction requires pumping, transportation, possibly treatment, and disposal of substantial volumes of extracted brackish or saline water, all of which can be technically challenging and expensive. This paper describes a constrained differential evolution (CDE) algorithm for optimal well placement and injection/ extraction control with the goal of minimizing brine extraction while achieving predefined pressure contraints. The CDE methodology was tested for a simple optimization problem whose solution can be partially obtained with a gradient-based optimization methodology. The CDE successfully estimated the true global optimum for both extraction well location and extraction rate, needed for the test problem. A more complex example application of the developed strategy was also presented for a hypothetical CO2 storage scenario in a heterogeneous reservoir consisting of a critically stressed fault nearby an injection zone. Through the CDE optimization algorithm coupled to a numerical vertically-averaged reservoir model, wemore » successfully estimated optimal rates and locations for CO2 injection and brine extraction wells while simultaneously satisfying multiple pressure buildup constraints to avoid fault activation and caprock fracturing. The study shows that the CDE methodology is a very promising tool to solve also other optimization problems related to GCS, such as reducing ‘Area of Review’, monitoring design, reducing risk of leakage and increasing storage capacity and trapping.« less

Coupling Basin and Reservoir Simulators for an Improved CO2 Injection Flow Model

Abstract The goal of this work is to model the present basin-scale groundwater flow of the Paris basin with a basin modelling approach and to use it to initialise a reservoir model for CO 2 injection. It is part of the ULTimateCO2 FP7 European funded project which aims to significantly enhance our knowledge of specific processes that may affect the long-term fate of geologically stored CO 2 . Basin models simulate the history of sedimentary basins through time by coupling geological events such as deposition, erosion, compaction, structural deformation and subsurface flow simulation. In order to construct the basin model of the Paris Basin in IFPEN basin software TemisFlow®, several types of data were gathered. The current surface topography and 11 horizons representing the top of selected main geological layers (from basement to surface) were constructed from outcrop boundaries, wells and isobath maps. Seven erosion maps for the main unconformities recorded in the Paris Basin were also constructed to complete the burial history of the sedimentary basin. TemisFlow® computes pressure, temperature and salinity fields over the basin history up to the present-day. The final state of the basin simulation is then used as initial state of the reservoir numerical model (Coores TM ). The latter is used to simulate the injection of CO 2 and its effects on the pressure field for instance.

Numerical Simulation of the Buried Hill Reservoir in Bohai Bay

Buried hill reservoir fracture description and reservoir simulation technology have been a hot research, but also is one of the key issues that restrict the efficient development of such reservoirs. Based on JZ buried hill reservoir which heterogeneity is strong, some wells water channeling fast and difficult to control the situation for fracture affect, a typical block of dual medium reservoir numerical models which was comprehensive variety of information, discrete fracture characterization and geological modeling is established. The fractured reservoir numerical model is simulated through Eclipse software to seek the law of remaining oil distribution. Through the reservoir geological reserves and production history matching, the remaining oil distribution of main production horizon is forecasted. On this basis, the results of different oilfield development adjustment programs are predicted by numerical simulation.

The Research on Distribution of the Remaining Oil in Heavy Oil Reservoir of BQ57

The BQ57 block is structurally located in the sag part of Biyang, the northern slopes. Reservoir is buried shallow, thickness thin and oil viscosity is high. With the old wells production factor decreasing, the remaining oil distribution is getting more and more complex, the block has a downward trend in production capacity. In this text, we longitudinally divided the BQ57 block into several emulation layers, horizontally divided into grids, established the block reservoir numerical model using the reservoir numerical simulation software, fit the daily fluid production, daily oil production, water cut, diurnal injection of this block, and the single well production history by adjusting the model parameter values, which the fitting error of each index were all within 2%[1,2]. On the basis of the results of numerical simulation, statistical analysis the remaining oil distribution and reserves abundance condition, clarify the regularities of distribution of the remaining oil, so that we can effectively produce the remaining oil, and it has an important significance for improving the recovery rate in oilfield.

A Reservoir/Wellbore‐Coupling Model for the Pressure, Flow Rate, and Optimum Perforation Distribution in Gas Wells

AbstractDue to the variation in pressure drawdown along a well, pressure drop can occur in a vertical well. Accurate prediction of the inflow performance for perforated vertical wells is of great significance to reservoir analysis and perforation optimization. Under steady‐state inflow, a reservoir/wellbore‐coupling model is proposed that combines a numerical reservoir model and a semianalytical wellbore model. One type of optimization problem is also established that considers the effects of perforation density on the productivity of a vertical well, for which the vertical‐well production is treated as an objective function. A number of experiments are presented demonstrating how the model could be used to obtain the optimum perforation distribution for infinite‐conductivity and finite‐conductivity wells.

Optimization Algorithms Used in Reservoir History Matching

Numerical reservoir models are constructed from limited available static and dynamic data, and history matching is a process of changing model parameters to find a set of values that will yield a reservoir simulation prediction of data that matches the observed historical production data. To minimize the objective function involved in the history matching procedure, we need to apply the optimization algorithms. This paper is based on the optimization algorithms used in automatic history matching. Several optimization algorithms will be compared in this paper.

The Effects of the Shear-thinning Property of Injection Fluid on the Performance of Polymer Flood

Assessment of the potential of a polymer flood process for mobility control requires an accurate model on the viscosities of displacement fluids. Because most polymers used in enhanced oil recovery exhibit shear-thinning behavior, effective viscosity of polymer solution is a highly nonlinear function of shear rate. A reservoir simulator, including the model for the shear-rate dependence of viscosity, was used to investigate the shear-thinning effects of polymer solution on the performance of the reservoir in a five-spot pattern operating under polymer flood followed by waterflood. The model can be used as a quantitative tool to evaluate the comparative studies of different polymer flooding scenarios with respect to shear-rate dependence of fluids' viscosities. Results of cumulative oil recovery, injectivity, and distributions of polymer concentration and aqueous phase viscosity are presented for parameters of shear-rate dependencies, permeability, and injection rate. The results of this work have proven the importance of taking non-Newtonian behavior of polymer solution into account for the successful evaluation of polymer flood processes. Simulations carried in a 3D model suggest that the shear-thinning property improves injectivity considerably because the shear rate encountered near the injection well alters the viscosity of displacing fluid. However, it makes almost negligible differences in oil recovery because a significant increase in viscosity was developed at the fluid front in the reservoir. A thorough understanding of polymer rheology in the reservoir and accurate numerical modeling are of fundamental importance for the exact estimation on the performance of polymer flood.

Quantification of diagenesis impact on the reservoir properties of the Jurassic Arab D and C members (Offshore, U.A.E.)

AbstractAn increasing need exists to quantify the impact of diagenesis on complex and heterogeneous geological reservoirs and to predict the related field‐scale porosity‐permeability distribution. Development of approaches to quantify diagenetic events is an important step towards the construction of integrated numerical reservoir models predicting the impact of successive diagenetic events on petrophysical properties at various scales. This article describes two distinct approaches, which allow capturing, quantifying and explaining reservoir heterogeneities of the Jurassic Arab Formation (offshore oilfield in Abu Dhabi, U.A.E.) at the field and plug scale. Based on a classical diagenesis study, whereby the major diagenetic phases were characterized, distribution patterns were highlighted to further explain reservoir heterogeneities through a set of 2D interpolation diagenesis maps across the field. The best reservoir properties are encountered in the central‐northern (grainstones with syntaxial calcite overgrowth cement – typical of Arab D) and south‐western (dolostones – typical of Arab C) parts of the oilfield. Following another independent approach at the scale of the plug, quantification of rock components and description of the pore space connectivity and geometry are obtained by 2D and 3D image analyses, μ‐CT and pore network modelling. This latter approach resulted in a better understanding of the effect of anhydrite dissolution on the pore structure of the investigated dolostone. The overall, presented workflow provides valuable constraints for assessing reservoir heterogeneities in statistical field‐scale models.

Numerical Simulation on the Dynamic Variation of Reservoir Pressure of Typical Coalbed Methane Single Well and Well Net Group—A Case Study on QN01 Well in the Southern Qinshui Basin, China

Based on the geological data and drainage parameters of QN01 coalbed methane (CBM) well which is located at the southern Qinshui Basin, by using CBM reservoir numerical modeling technology, 15 years' gas recoverability is predicted and the dynamic variation of reservoir pressure is studied for both QN01 well and an assumed 300 × 300m well net group by using the same parameters as QN01 well. The results show that for single well, within the first 300 days, gas recoverability is similar everywhere in the gas supply area and the dropping rates of reservoir pressure are all below 1 KPa/d. Further more, the region more than 120 m away from the well bore hole is not beneficial for gas recoverability. For well net group, dropping rates of reservoir pressure are higher than 1 KPa/d. With the increase of the distance to the well bore hole, gas outcomes more and more in the gas supply area. Similarly, the “secondary reservoir pressure dropping” caused by the well interference in the well net group has a positive correlation with the distance to the well bore hole, and the dropping rates of reservoir pressure of the well net group are approximately twice as large as those of the single well.

A new method to optimize the fracture geometry of a frac-packed well in unconsolidated sandstone heavy oil reservoirs

The worldwide proven recoverable reserves of conventional oil are less than the amount of the heavy oil. Owing to weakly consolidated formation, sand production is an important problem encountered during oil production in heavy oil reservoirs, for which frac-pack technique is one of the most common treatments. Hence, how to obtain the optimal fracture geometry is the key to increasing well production and preventing sand. Due to the faultiness that current optimization of the fracture geometry only depends on well productivity, fracture-flow fraction was used to describe the contribution of the fracture collecting and conducting fluids from the reservoir. The higher the fracture-flow fraction, the more likely bilinear flow pattern occurs, thus leading to smaller flow resistance and better results in oil productivity and sand prevention. A reservoir numerical simulation model was established to simulate the long-term production dynamic of a fractured well in rectangular drainage areas. In order to reach the aim of increasing productivity meanwhile preventing sand, a new method based on Unified Fracture Design was developed to optimize the fracture geometry. For a specific reservoir and a certain amount of proppant injected to the target layer, there exits an optimal dimensionless fracture conductivity which corresponds to the maximum fracture-flow fraction, accordingly we can get the optimal fracture geometry. The formulas of the optimal fracture geometry were presented on square drainage area conditions, which are very convenient to apply. Equivalent Proppant Number was used to eliminate the impact of aspect ratios of rectangular drainage area, then, the same method to optimize the fracture geometry as mentioned for square drainage areas could be adopted too.

Impact of a large tropical reservoir on riverine transport of sediment, carbon, and nutrients to downstream wetlands

Large dams can have major ecological and biogeochemical impacts on downstream ecosystems such as wetlands and riparian habitats. We examined sediment removal and carbon (C), nitrogen (N), and phosphorus (P) cycling in Itezhi‐Tezhi Reservoir (ITT; area = 364 km2, hydraulic residence time = 0.7 yr), which is located directly upstream of a high ecological value floodplain ecosystem (Kafue Flats) in the Zambezi River Basin. Field investigations (sediment cores, sediment traps, water column samples), mass balance estimates, and a numerical biogeochemical reservoir model were combined to estimate N, P, C, and sediment removal, organic C mineralization, primary production, and N fixation. Since dam completion in 1978, 330 × 103 tons (t) of sediment and 16 × 103, 1.5 × 103, 200 t of C, N, and P, respectively, have accumulated annually in ITT sediments. Approximately 50% of N inputs and 60% of P inputs are removed by the reservoir, illustrating its potential in decreasing nutrients to the downstream Kafue Flats floodplain. The biogeochemical model predicted substantial primary production in ITT (∼280 g C m−2 yr−1), and significant N‐fixation (∼30% for the total primary production) was required to support primary production due to marginal inputs of inorganic N. Model simulations indicate that future hydropower development in the reservoir, involving the installation of turbines driven by hypolimnetic water, will likely result in the delivery of low‐oxygen waters to downstream ecosystems and increased outputs of dissolved inorganic N and P by a factor of ∼4 and ∼2 compared to current dam management, respectively.

The geothermal project Den Haag: 3D numerical models for temperature prediction and reservoir simulation

The proposed Den Haag Zuidwest district heating system of the city of The Hague consists of a deep doublet in a Jurassic sandstone layer that is designed for a production temperature of 75 °C and a reinjection temperature of 40 °C at a flow rate of 150 m 3 h −1. The prediction of reservoir temperature and production behavior is crucial for success of the proposed geothermal doublet. This work presents the results of a study of the important geothermal and geohydrological issues for the doublet design. In the first phase of the study, the influences of the three-dimensional (3D) structures of anticlines and synclines on the temperature field were examined. A comprehensive petrophysical investigation was performed to build a large scale 3D-model of the reservoir. Several bottomhole temperatures (BHTs), as well as petrophysical logs were used to calibrate the model using thermal conductivity measurements on 50 samples from boreholes in different lithological units in the study area. Profiles and cross sections extracted from the calculated temperature field were used to study the temperature in the surrounding areas of the planned doublet. In the second phase of the project, a detailed 3D numerical reservoir model was set up, with the aim of predicting the evolution of the producer and injector temperatures, and the extent of the cooled area around the injector. The temperature model from the first phase provided the boundary conditions for the reservoir model. Hydraulic parameters for the target horizons, such as porosity and permeability, were taken from data available from the nearby exploration wells. The simulation results are encouraging as no significant thermal breakthrough is predicted. For the originally planned location of the producer, the extracted water temperature is predicted to be around 79 °C, with an almost negligible cooling in the first 50 years of production. When the producer is located shallower parts of the reservoir, the yield water temperatures is lower, starting at ≈76 °C and decreasing to ≈74 °C after 50 years of operation. This comparatively larger decrease in temperature with time is caused by the structural feature of the reservoir, namely a higher dip causes the cooler water to easily move downward. In view of the poor reservoir data, the reservoir simulation model is constructed to allow iterative updates using data assimilation during planned drilling, testing, and production phases. Measurements during an 8 h pumping test carried out in late 2010 suggest that a flow rate of 150 m 3 h −1 is achievable. Fluid temperatures of 76.5 °C were measured, which is very close to the predicted value.

Drilling Through Gas-Hydrate Sediments: Managing Wellbore-Stability Risks

Summary As hydrocarbon exploration and development moves into deeper water and onshore Arctic environments, it becomes increasingly important to quantify the drilling hazards posed by gas hydrates. To address these concerns, a 1D semianalytical model for heat and fluid transport in the reservoir was coupled with a numerical model for temperature distribution along the wellbore. This combination allowed the estimation of the dimensions of the hydrate-bearing layer where the initial pressure and temperature can dynamically change while drilling. These dimensions were then used to build a numerical reservoir model for the simulation of the dissociation of gas hydrate in the layer. The bottomhole pressure (BHP) and formation properties used in this workflow were based on a real-field case. The results provide an understanding of the effects of drilling through hydrate-bearing sediments (HBS) and of the impact of drilling-fluid temperature and BHP on changes in temperature and pore pressure within the surrounding sediments. It was found that the amount of gas hydrate that can dissociate will depend significantly on both initial formation characteristics and bottomhole conditions) namely, mud temperature and pressure). The procedure outlined in the paper can provide quantitative results of the impact of hydrate dissociation on wellbore stability, which can help in better design of drilling muds for ultradeepwater operations.

Initiation of a secondary hydraulic fracture and its interaction with the primary fracture

Laboratory and field experiments have shown that secondary fracture treatment along a different direction to the primary hydraulic fracture can increase the recovery of gas from tight sands. Success of a restimulation treatment (secondary fracture treatment) is, however, highly dependent on transient stress distribution around the well. In this paper a numerical poroelastic reservoir model is used to provide a more realistic picture of stress field around a stimulated well during post-fracture production. Initiation of a re-oriented hydraulic fracture and its interaction with the primary hydraulic fracture are also studied using a wellbore re-pressurization model that includes a poroelastic formation, a wellbore and a pair of finite conductive hydraulic fractures. Numerical results have shown that during post-fracture production the directions of maximum and minimum horizontal stresses are reversed within a large area around the wellbore and the hydraulic fractures. We have also shown that relatively small areas exist at the wellbore wall where the original directions of horizontal principal stresses remain unchanged. It is shown that the presence of these small areas could act against initiation of a secondary hydraulic fracture along the most desired directions in terms of recovery enhancement. This study also shows that oriented perforations prior to refracture treatment help initiate secondary fractures in a preferred direction before the primary hydraulic fractures start propagation during re-pressurisation of the wellbore.

Simulating the heterogeneity in braided channel belt deposits: 1. A geometric‐based methodology and code

A geometric‐based simulation methodology was developed and incorporated into a computer code to model the hierarchical stratal architecture, and the corresponding spatial distribution of permeability, in braided channel belt deposits. The code creates digital models of these deposits as a three‐dimensional cubic lattice, which can be used directly in numerical aquifer or reservoir models for fluid flow. The digital models have stratal units defined from the kilometer scale to the centimeter scale. These synthetic deposits are intended to be used as high‐resolution base cases in various areas of computational research on multiscale flow and transport processes, including the testing of upscaling theories. The input parameters are primarily univariate statistics. These include the mean and variance for characteristic lengths of sedimentary unit types at each hierarchical level, and the mean and variance of log‐permeability for unit types defined at only the lowest level (smallest scale) of the hierarchy. The code has been written for both serial and parallel execution. The methodology is described in part 1 of this paper. In part 2 (Guin et al., 2010), models generated by the code are presented and evaluated.