Reservoir Geological Model Research Articles

Study on Geological Modeling of Heidimiao and Fuyang Oil Layer in Da’an North Area

In this paper, through the study of reservoir geological modeling, the reservoir modeling software is used to establish the reservoir 3D geological model; combined with the sedimentary microfacies research results, the reservoir sedimentary microfacies model is established; using geostatistics and stochastic simulation methods, the small layer performs stochastic modeling of porosity, permeability and oil saturation properties, and establishes a three-dimensional model of the properties under the control of reservoir sedimentary facies.

3D Reservoir Modeling Based on Mobile Platform and OpenGL ES

This paper discusses 3D petroleum reservoir modeling based on android platform and development of relavite graphical software system for reservoir models on the mobile terminal. Using OpenGL ES graphical library to perform graphics processing and realize 3D rendering of the mobile reservoir models. Making use of the Kriging algorithm and Choleskly method to accomplish the interpolation calculation, it is the core of all grid vertexes algorithm and cutting operation for the reservoir models. On the basis of 3D reservoir modeling, complete several 3D reservoir geological model maps, and a serial of functional maps such as rotation, translation, scaling and grid displays, peeling, axis slicing, arbitrary slicing, well connected section, etc. The software system successfully passed the tests of some oil field data. The 3D reservoir modeling based on mobile platform enables the professional persons to analyse the reservoir distribution and direct the oil well drilling feasibly and easily, which will bring great convenience for technical exchanges of oil and gas exploration.

Geological Model of the Tight Reservoir (Sadi Reservoir-Southern of Iraq)

A3D geological model was constructed for Al-Sadi reservoir/ Halfaya Oil Field which is discovered in 1976 and located 35 km from Amara city, southern of Iraq towards the Iraqi/ Iranian borders.
 Petrel 2014 was used to build the geological model. This model was created depending on the available information about the reservoir under study such as 2D seismic map, top and bottom of wells, geological data & well log analysis (CPI). However, the reservoir was sub-divided into 132x117x80 grid cells in the X, Y&Z directions respectively, in order to well represent the entire Al-Sadi reservoir.
 Well log interpretation (CPI) and core data for the existing 6 wells were the basis of the petrophysical model (Porosity, Water saturation, & Permeability) that were distributed for all the created grids and then upscaled.

LoggingTechnology Applied to Three-dimensional Geological Modelling

Reservoir geological modelling is indispensable to the fine description of reservoir. The geological models can be combined with related technologies such as spatial information management, geological interpretation, geostatistics, spatial analysis and prediction, and physical content analysis. It can quantitatively characterize the various characteristic parameters of the reservoir, the basic geometric shape of the geologic body and the distribution of the data. The application of logging technology is very extensive, and the analysis and processing of logging data are very important for stratigraphic division, lithology analysis, and oil-water layer identification. In this paper, the well logging data of the Huaziping area in the oilfield is used as the object, and the geological modeling and geologic characteristics and the evaluation of the oil and gas layers are studied through geological modeling. Thereby achieving the guiding role of further development and utilization of the reservoir.

Reservoir Geological Modeling Technique and Quality Control Method

Reservoir Geological Modeling Technique and Quality Control Method

Sequence stratigraphic approaches for reservoir modeling, Arshad area, Sirt Basin, Libya

Sequence stratigraphic analysis has been used to support the reservoir geological modeling of the Upper Cretaceous succession of the Arshad area, Sirt Basin, Libya. Four major sedimentary cycles (1–4) can be distinguished in the succession of the Arshad area which can be related to the standard Mesozoic cycle charts. These cycles are bounded by five sequence boundaries (SB types 1 and 2). Sedimentary cycle number 1 is represented by retrogradational patterns (shale and minor carbonates) at the base of the Arshad Formation, which pinch out to the south. Sedimentary cycle number 2 comprises a prograding pattern in the lower part (Arshad Formation) passing upward into retrograding patterns of the Sirte Formation in the upper part. This cycle includes reworked clastics of the underlying (Cambro-Ordovician) Gargaf Formation. These sandstone-dominated shallow-marine facies include the principal hydrocarbon-bearing reservoirs in the study area. The sedimentary cycles nos. 3 and 4 are composed mainly of shales and limestones (Sirte and Kalash formations), representing the main hydrocarbon source rocks and cap rocks for the underlying sandstone reservoirs in the Sirt Basin. These sediments trace the sea level changes, and increasing water depth above the major Hercynian sequence boundary. These sedimentary cycles are affected by syn-depositional tectonics which control the distribution of the hydrocarbon-bearing sands plus post-depositional changes (diagenesis) which affect the reservoir quality and performance (porosity-permeability relationship).

Constraints of three-dimensional geological modeling on reservoir connectivity: A case study of the Huizhou depression, Pearl River Mouth basin, South China Sea

The Z21 gas field is the only one gas field in the Huizhou depression. The distributions of sandstone and mudstone in the adjacent west zone control the extent of the Z21 gas field, making the confirmation of the reservoir connectivity between the west zone and main zone (RCWM) crucial. In this study, a practical workflow was proposed to confirm the RCWM. First, the sandstone and mudstone distributions were modeled by a sequential indicator simulation, using the vertical proportion curves as constraints. The porosity and permeability distributions were then predicted using a sequential Gaussian simulation based on sandstone and mudstone models. The sandstone, mudstone, and physical property models were treated as components of a geological embryonic model (GEM) prior to the RCWM confirmation. Different hypotheses on the RCWM of the GEMs were drawn, bringing variations to the GEMs and the GEMs turned to be different new models. These new models were then applied to numerical simulations, not only to perform quality checks, but also to attain the simulated formation pressure coefficients (Pfcs) and couple the study with the current formation pressure coefficients (Pfcc) derived from the modular formation dynamics tester (MDT). A hypothesis is negated if the Pfcs is not equal or approximately equal to the Pfcc. A coupled result was iteratively generated until the RCWM was confirmed. This coupling study on reservoir connectivity makes use of general geological reservoir models and highlights the ingenious designs based on different hypotheses of the RCWM to generate reliable results. Coupling study shows that distributions of formation pressure in the west zone of Z21 field are largely affected by a low-permeability belt and RCWM is proved weak due to the existence of the low-permeability belt.

3D numerical simulation of clastic reservoir with bottom water drive using various ior techniques for maximizing recovery

In most reservoirs with oil rims, as the production begins, the gas–oil and oil–water fluid interfaces start deforming because of the imbalance between viscous and gravitational forces, leading to coning or cusping. This can be overcome using proper withdrawal rate, offset from water–oil contact and horizontal length. Further smart horizontal wells require optimization of nozzle size and compartment length also. To see the effect of these parameters on recovery, a three-dimensional geological model of a clastic reservoir from Upper Assam Basin has been used. This model was history matched for a period of 16 years on 46 wells. After successful validation of model on field scale and well level, performance prediction was carried out to see the effect of withdrawal rate, offset from water–oil contact, horizontal length, compartment length and nozzle size using vertical/horizontal and ICD completion. From the analysis, it is evident that application of advanced well completion, ICD, is suitable for such reservoir. Depending on the scenario, maximum cumulative oil production was obtained from ICD wells with 1.08 MMm3 compared to vertical well with cum oil production of 0.63 MMm3. Economic analysis has been carried out for the examined scenarios.

Three-Dimensional Reservoir Modeling Using Stochastic Simulation, a Case Study of an East African Oil Field

This paper presents a three-dimensional geological reservoir model created using stochastic simulation. The oil field presented is an East African oil field formed by a structural trap. Data analysis and transformations were conducted on the properties before simulation. The variogram was used to measure the spatial correlation of cell-based facies modeling, and porosity and permeability modeling. Two main lithologies were modelled using sequential indicator simulation, sand and shale. Sand had a percentage of 26.8% and shale of 73.2%. There was a clear property distribution trend of sand and shale from the southwest to the northeastern part of a reservoir. The distribution trend of the facies resembled the proposed depositional model of the reservoir. Simulations show that average porosity and permeability of the reservoir are about 20% and 1004 mD, respectively. Average water saturation was 64%. STOIIP volume of 689.42 MMbbls was calculated. The results of simulation showed that the south eastern part of the reservoir holds higher volumes of oil. In conclusion, the model gave a better geological understanding of the geology of the area and can be used for decision making about the future development of the reservoir, prediction performance and uncertainty analysis.

Big data paradox and modeling strategies in geological modeling based on horizontal wells data

Abstract Based on analysis of horizontal well data characteristics, the differences of data distribution and variogram between vertical and horizontal wells in MPE3 oil field of Orinoco heavy oil belt were compared, and modeling strategies were proposed to cope with the big data paradox when data of horizontal wells was used directly into geologic modeling. The study shows the horizontal wells in the study area contain a large quantity of information, strong directionality of well trajectories and high drilling ratio of sandstone, causing variogram analysis result unconformable to the geologic understanding, and in turn making errors in the modeling of sedimentary microfacies and reservoir physical properties and prediction of probabilistic reserves. Firstly, the distributary channel distribution variogram was analyzed with data of vertical wells, and then the lithofacies framework was established under the control of the sedimentary facies and seismic data. After that, the horizontal wells data revealing high heterogeneity accuracy of reservoir, was combined with the vertical wells data to analyze argillaceous interlayer variograms and the corresponding reservoir lithofacies models were constructed. Finally, reservoir physical property models were generated and the geological reserves were calculated by wellblocks. This reservoir modeling method does not only reflect the geologic features underground, but also improve the accuracy of inter-well sand body prediction, and enhance the reliability of reservoir geologic model ultimately.

Application of 3D Stress Model in Horizontal Well Fracturing Optimization Design

In the traditional optimization design of multi-stage fracturing in horizontal wells, the rock mechanics and stress profiles of the vetical section of horizontal well or other vertical wells near the perforated cluster are usually borrowed. In the strong heterogeneity reservoirs, there is a large deviation between the design results and the microseismic monitoring results. In this paper, based on the three dimensional geological model of reservoir, the stress and the rock mechanics parameter model are builded, the stress and rock parameters of vertical profile at each perforation center are extracted, we can evaluate the difficulty of fracture extending in different position, by adjusting the number of perforations to achieve the best stimulation effect.

Revising the Static Geological Reservoir Model of the Upper Triassic Stuttgart Formation at the Ketzin Pilot Site for CO2 Storage by Integrated Inverse Modelling

The Ketzin pilot site for CO 2 storage in Germany has been operated from 2007 to 2013 with about 67 kt of CO 2 injected into the Upper Triassic Stuttgart Formation. Main objectives of this undertaking were assessing general feasibility of CO 2 storage in saline aquifers as well as testing and integrating efficient monitoring and long-term prediction strategies. The present study aims at revising the latest static geological reservoir model of the Stuttgart Formation by applying an integrated inverse modelling approach. Observation data considered for this purpose include bottomhole pressures recorded during hydraulic testing and almost five years of CO 2 injection as well as gaseous CO 2 contours derived from 3D seismic repeat surveys carried out in 2009 and 2012. Inverse modelling results show a remarkably good agreement with the hydraulic testing and CO 2 injection bottomhole pressures (R 2 = 0.972), while spatial distribution and thickness of the gaseous CO 2 derived from 3D seismic interpretation exhibit a generally good agreement with the simulation results (R 2 = 0.699 to 0.729). The present study successfully demonstrates how the integrated inverse modelling approach, applied for effective permeability calibration in a geological model here, can substantially reduce parameter uncertainty.

Application of Reservoir Flow Simulation Integrated with Geomechanics in Unconventional Tight Play

Multistage hydraulic fracturing techniques, combined with horizontal drilling, have enabled commercial production from the vast reserves of unconventional tight formations. During hydraulic fracturing, fracturing fluid and proppants are pumped into the reservoir matrix to create the hydraulic fractures. Understanding the propagation mechanism of hydraulic fractures is essential to estimate their properties, such as half-length. In addition, natural fractures are often present in tight formations, which might be activated during the fracturing process and contribute to the post-stimulation well production rates. In this study, reservoir simulation is integrated with rock geomechanics to predict the well post-stimulation productivities. Firstly, a reservoir geological model is built based on the field data collected from the Montney formation in the Western Canadian Sedimentary Basin. The hydraulic fracturing process is then simulated through an integrated approach of fracturing fluid injection, rock geomechanics, and tensile failure criteria. In such a process, the reservoir pore pressure increases with a continuous injection of the fracturing fluid and proppants, decreasing the effective stress exerted on the rock matrix accordingly as the overburden pressure remains constant. Once the effective stress drops to a threshold value, tensile failure of the reservoir rock occurs, creating hydraulic fractures in the formation. The early production history of the stimulated well is history-matched to validate the predicted fracture geometries (e.g., half-length) generated from the fracturing simulation process. The effects of the natural fracture properties and well bottom-hole pressures on well productivity are also studied. It has been found that nearly 40% of hydraulic fractures propagate in the beginning stage (the pad step) of the fracturing schedule. In addition, well post-stimulation productivity will increase significantly if the natural fractures are propped or partially propped by the proppants. This paper provides insights on fracture propagation and can be a reference for fracturing treatments in unconventional tight reservoirs.

Inverse modelling of hydraulic testing to revise the static reservoir model of the Stuttgart Formation at the Ketzin pilot site

Pilot-scale CO2 storage has been performed at the Ketzin pilot site in Germany from 2007 to 2013 with about 67 kt of CO2 injected into the Upper Triassic Stuttgart Formation, focussing on efficient monitoring and long-term prediction strategies. We employed inverse modelling to revise the latest static geological reservoir model, considering bottomhole well pressures observed during hydraulic testing. Simulation results exhibit very good agreement with the observations, providing one reasonable permeability realization for the Ketzin pilot site near-well area. Furthermore, an existing hypothesis on the presence of a low-thickness sandstone channel between two wells is supported by our findings.

An Approach to Estimation of Gas Reserve of Narshingdi Gas Field in Bangladesh with Dynamic Reservoir Simulation

Increasing demand of fuel globally formulates gas as one of the most valuable natural resources. There is lot of uncertainties in estimating hydrocarbon volume correctly from exploration to development stage of a gas field. The accuracy and reliability of data (reservoir geological model, fluid and rock properties) make the implement very hard-hitting. So estimating and updating the gas reserve has become vital issue, as it helps the planners for drawing mid-term and long-term development plan from field development level to national level. This paper presents the study of reserve estimation of a Narshingdi Gas Field in Bangladesh. In this paper, a dynamic reservoir simulation model has been used to perform a history match ?pressure and production? using commercial simulator for reserve estimation. The result of this study is expected to provide Gas Initially in Place (GIIP) and recoverable gas volume. Simultaneously three forecast scenarios have also been investigated. There is no strong aquifer pressure support in the producing gas zone, so gas production continues from the reservoir due to pressure depletion.Journal of Chemical Engineering, Vol. 29, No. 1, 2017: 19-23

Geological Reservoir Characterization and Modelling of a CO2 Storage Aquifer: A Case Study of the Nagaoka Site, Japan

Site characterization is critical for safe and effective geological storage of CO2 because geological heterogeneity affects reservoir quality, plume migration, and trapping. This study shows geological characterization and modeling of a CO2 storage aquifer near Nagaoka, Japan. Core and well-logging analysis show that the target aquifer consists of deltaic deposits, which are characterized by a fining-upward to coarsening-upward succession that has developed on a ravinement surface. The target aquifer is attributed to prodelta and deltafront deposits. A geostatistical method known as sequential Gaussian simulation with collocated cokriging was applied to generate a spatial distribution of petrological and physical properties including shale volume, porosity, and permeability. The simulation was performed using well-log data as a primary variable and seismic-derived porosity data as a secondary variable under the constraints of correlation coefficient between variables. Simulated models showed that impermeable fine-grained deposits are distributed toward the east. This trend can explain the fact that breakthrough has not been observed at an observation well located farthest to the west from the injection well, IW-1. This result is consistent with previously proposed paleogeographic interpretations that show that detrital particles are transported from east to west at the Nagaoka site.

Mapping of water and gas injection areas through modeling and interpretation of 4D seismic from reservoir simulation models

Using an integrated approach of reservoir simulation, rock physics and seismic modeling, the present study analyzes the influence of changes in pressure and fluid saturation on synthetic time-lapse seismic sections. The forms and occasions in which these changes can be detected on 4D seismic are studied, to help in the characterization of the fluid flow inside the reservoir. To analyze these effects, reservoir production simulations were conducted in a geological model of a sandstone reservoir in the Campos Basin, offshore SE Brazil. Through direct petro-elastic and seismic modeling, 4D impedance volumes were created using simulation results, and corresponding synthetic seismic volumes were computed. Simulations of both water injection and gas injection scenarios were conducted in order to quantify the differences between oil-water and oil-gas substitutions and investigate how they affect the seismic amplitudes in a sandstone reservoir. The interpretations allow the definition of patterns to identify pressure and saturation related anomalies and to distinguish areas of water and gas injection.

Successful application of multiscale methods in a real reservoir simulator environment

For the past 10 years or so, a number of so-called multiscale methods have been developed as an alternative approach to upscaling and to accelerate reservoir simulation. The key idea of all these methods is to construct a set of prolongation operators that map between unknowns associated with cells in a fine grid holding the petrophysical properties of the geological reservoir model and unknowns on a coarser grid used for dynamic simulation. The prolongation operators are computed numerically by solving localized flow problems, much in the same way as for flow-based upscaling methods, and can be used to construct a reduced coarse-scale system of flow equations that describe the macro-scale displacement driven by global forces. Unlike effective parameters, the multiscale basis functions have subscale resolution, which ensures that fine-scale heterogeneity is correctly accounted for in a systematic manner. Among all multiscale formulations discussed in the literature, the multiscale restriction-smoothed basis (MsRSB) method has proved to be particularly promising. This method has been implemented in a commercially available simulator and has three main advantages. First, the input grid and its coarse partition can have general polyhedral geometry and unstructured topology. Secondly, MsRSB is accurate and robust when used as an approximate solver and converges relatively fast when used as an iterative fine-scale solver. Finally, the method is formulated on top of a cell-centered, conservative, finite-volume method and is applicable to any flow model for which one can isolate a pressure equation. We discuss numerical challenges posed by contemporary geomodels and report a number of validation cases showing that the MsRSB method is an efficient, robust, and versatile method for simulating complex models of real reservoirs.

A method of production profile quick prediction based on typical curves: A case study of the Upper Shale large multi-layered sandstone reservoir, Rumaila Oilfield, Iraq

Abstract Combined the advantage of reservoir simulation and conventional reservoir engineering methods, the paper proposes a quick method for production performance prediction, which is based on type curves generated from reservoir simulations of sector model. Fine reservoir simulation is conducted based on the fine geological sector model of the large sandstone reservoir, and type curves of different reservoir type under different development options are generated. Then based on results of reservoir type classification for all layers, well productivity and injectivity evaluation, production profile of the whole field can be predicted. This new method can reflect the impact of reservoir heterogeneity and development option change on reservoir performance. Take a large multi-layered sandstone reservoir Upper Shale reservoir in Rumaila Oilfield for example to illustrate the workflow. The comparison between results of fine reservoir simulation and that of the new method validate reliability of the new method, and the new method consume much shorter time.

Experimental and numerical evaluation of CO2 huff-n-puff processes in Bakken formation

Experimental and numerical techniques have been developed to evaluate performance of CO2 huff-n-puff processes for unlocking resources from the Bakken tight oil formations. Experimentally, a series of coreflooding tests have been conducted by using core samples collected from the Bakken tight formation with a permeability range of 0.27–0.83mD. The performance of four recovery schemes (i.e., waterflooding, immiscible CO2 huff-n-puff, near-miscible CO2 huff-n-puff, and miscible CO2 huff-n-puff processes) has been comparatively evaluated. Theoretically, numerical simulation is performed to match the experimental measurements and then extended for evaluating field-scale CO2 huff-n-puff performance in the Bakken formation. Once the history matching on either the experimental measurements or the field geological model is completed, the tuned numerical model is then employed to optimize the injection pressure, soaking time, and production pressure, respectively. It is experimentally found that the waterflooding process leads to a higher oil recovery factor of 51.5% in comparison with the immiscible CO2 huff-n-puff process, while both the near-miscible and miscible CO2 huff-n-puff processes result in a higher recovery efficiency with the final recovery factors of 63.0% and 61.0% of OOIP, respectively. As for the history matched reservoir geological model, either a higher injection pressure or a lower production pressure usually results in better recovery performance but lower than the corresponding experimental measurements, while recovery factor can be optimized if soaking time of 15days is applied in this study.