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Abstract The need to develop new tools that allow reservoir engineers to optimize reservoir performance is becoming more demanding by the day. One of the most challenging and influential problems facing reservoir engineers is well placement optimization. The North Kuwait field (NKF) consists of six fields containing four naturally fractured carbonate formations. The reservoirs are composed of relatively tight limestone and dolomite embedded with anhydrate and shale. The fields are divided into isolated compartments based on fault zones and supported by a combination of different fluid compositions, initial pressures, and estimated free-water levels. Due to natural complexity, tightness, and high drilling costs of wells in the NKF, it is very important to identify the sweet spots and the optimum well locations. This paper presents two intelligent methods that use dynamic numerical simulation model results and static reservoir properties to identify zones with a high-production potential: reservoir opportunity index (ROI) and simulation opportunity index (SOI). The Petrel* E&P software platform was chosen as the integrated platform to implement the workflow. The fit-for-purpose time dependent 2D maps generated by the Petrel platform facilitated the decision-making process used for locating new wells in the dominant flow system and provided immense support for field-development plans. The difference between the two methods is insignificant because of reservoir tightness, limited interference, and natural uncertainty on compartmentalization. At this stage, pressure is not a key parameter. As a result, unlike brown fields, less weight was given to simulated pressure, and SOI was used to select the well locations. The results of this study show that implementing these workflows and obtaining the resulting maps significantly improve the selection process to identify the most productive areas and layers in a field. Also, the optimum numbers of wells using this method obtained in less time and with fewer resources are compared with results using traditional industry approaches.
- Asia > Middle East > Kuwait > Jahra Governorate > Arabian Basin > Widyan Basin > North Kuwait Jurassic (NKJ) Fields > Marrat Formation > Upper Marrat Formation (0.98)
- Asia > Middle East > Kuwait > Jahra Governorate > Arabian Basin > Widyan Basin > North Kuwait Jurassic (NKJ) Fields > Marrat Formation > Sargelu Formation (0.98)
Abstract Resistivity measurements play a key role in hydrocarbon in place calculations for oil and gas reservoirs. They are a direct indicator of fluid saturation and connected pore space available in the formation. Carbonate rocks, which host around half of the world's hydrocarbons, exhibit a wide range of porosities with scales spanning from nanometres to centimetres. The often significant amount of microporosity displayed by Carbonate rocks emphasizes the necessity of an adequate characterization of their micro-features and their contribution to hydrocarbon in place. In this paper we examine upscaling methods to probe formation factor of a fully saturated carbonate sample using an X-ray CT based numerical approach and compare to experimental measurements. Three-dimensional high-resolution X-ray CT enables the numerical calculation of petrophysical properties of interest at the pore scale with resolutions down to a few microns per voxel. For more complex and heterogeneous samples however, a direct calculation of petrophysical properties is not feasible, since the required resolution and a sufficient field of view cannot be obtained simultaneously. Thus an integration of measurements at different scale is required. In this study a carbonate sample of 38mm in diameter is first scanned using the X-ray CT method with a resolution of 26 ยตm. After accompanying experimental measurements on the full plug, four 5mm plugs were drilled vertically from this sample and X-ray CT images of these plugs acquired at resolutions down to 2.74 ยตm. We calculate the porosity of the sample (macro- and micro-porosities) using the phase separation methods and then predict the formation factor of the sample at several scales using a Laplace solver. The formation factor is calculated by using a general value of m=2 as cementation factor for intermediate porosity voxels. We compare to experimental measurements of formation factor and porosity both at the small plug and full plug scale and find good agreement. To assess the degree of uncertainty of the numerical estimate, we probe the extent of heterogeneity by investigating the size of a representative elementary volume (REV) for formation factor. We find that for the considered heterogeneous carbonate sample, formation factor varies considerably over intervals less than a centimetre. Our results show that this variation could be explained by different cementation exponents applied at the micro-voxel scale, with the exemption of one plug, for which the cementation exponent would have to be unreasonably low. These cementation factors are derived by direct comparison between numerical simulation and experiment. We conclude that for one plug an error in experimental measurement might have occurred. The numerical approach presented here therefore aids in quality control. Excluding this plug in the upscaling procedure improves the agreement with the experimental result for the whole core while still underestimating formation factor. Allowing for a constant m=2 in the simulation at the small scale and using directly the resulting relationship between porosity and formation factor in the upscaling process leads to an overestimation of formation factor.
- North America > United States > Texas (0.46)
- Asia > Middle East > Saudi Arabia (0.28)
- North America > United States > Texas > Permian Basin > Yeso Formation (0.99)
- North America > United States > Texas > Permian Basin > Yates Formation (0.99)
- North America > United States > Texas > Permian Basin > Wolfcamp Formation (0.99)
- (26 more...)
Abstract This paper describes a workflow that was applied to a carbonate field in Oman to derive fracture and effective permeability models that were validated with multiple blind wells and reservoir simulation. The studied block is the largest and most faulted within a field which is currently under water-flood FDP. The study was kicked off with extensive borehole image interpretation. In parallel, several high resolution seismic inversions and spectral imaging attributes were generated as drivers to geological and fracture modelling. High resolution seismic was used to highlight subtle faults. Facies changes were also visible from seismic as seen in cored wells. Sequential geological modelling of GR, density, porosity and SW was carried out and constrained by seismic attributes. The derived fracture frequency logs were compared against geological, structural and seismic drivers in a process called driver ranking. The results confirmed the role of faults as well as facies being primary controls of fracturing. Subsequently, the screened and cross-correlated potential drivers were carried forward to constrain the fracture models. Multiple stochastic realizations were derived through neural network training and testing and an average model was kept. Final models were validated against hidden BHI data. A new BHI was used to confirm model prediction. Different types of dynamic data in non-BHI wells were also used to validate the fracture models as specific production/injection related issues could be directly linked to presence of fractures. These data include PLT, PTA and tracer tests from which injectivity issues and short circuiting were explained by higher fracture densities and corridors derived from modeling. Through dynamic calibration, the fracture model was converted to fracture permeability. The fracture permeability is the product of fracture density and a scaling factor derived from history matching. Subsequently, the addition of matrix permeability and fracture permeability will determine the effective permeability. This Keffective was directly used in the reservoir simulator without upscaling since it was part of the same grid hosting the fracture models. The results were encouraging as the simulation was smooth and error-free.
- Geophysics > Seismic Surveying > Seismic Interpretation (0.37)
- Geophysics > Seismic Surveying > Borehole Seismic Surveying (0.34)
- Geophysics > Seismic Surveying > Seismic Modeling (0.34)
Developing High Resolution Static and Dynamic Models for Waterflood History Matching and EOR Evaluation of a Middle Eastern Carbonate Reservoir
Masalmeh, S. K. (Shell Technology Oman) | Wei, Lingli (Shell China Innovation and R&D) | Hillgartner, H.. (Shell Technology Oman) | Al-Mjeni, R.. (Shell Technology Oman) | Blom, C.. (Shell Technology Oman)
Abstract Enhanced oil recovery (EOR) has become increasingly important to maintain and extend the production plateaus of existing oil reservoirs. Simulation models for EOR studies require the right level of spatial resolution to capture reservoir heterogeneity. Data acquired from the dedicated observation wells are essential in defining the required resolution to capture reservoir heterogeneity. For giant reservoirs with long production history, their full field models usually have grid block sizes that are of similar scale as the distance between injectors and observation wells, with the consequence of losing the value of the time lapse saturation logs from dedicated observation wells. Therefore, using high resolution sector models, especially from the part of the reservoir where static and dynamic data sets are rich, is a must. The objective of this paper is to present an improved and integrated reservoir characterization, modelling and water and gas injection history matching procedure of a giant Cretaceous carbonate reservoir in the Middle East. The applied workflow integrates geological, petrophysical, and dynamic data in order to understand the production history and the remaining oil saturation distribution in the reservoir. Large amounts of field data, including time lapse saturation logs from observation wells, have been collected over the last decades to provide insight into the sweep efficiency and flow paths of the injected water. Iterative simulations were performed to investigate different scenarios and various sensitivities with each iteration involving an update of the static model to honor both the dynamic and core/log data. While applying this iterative process it was also acknowledged that conventional core data (e.g. 1 plug per foot) may not capture the high permeability streaks in these heterogeneous reservoirs that control much of the reservoir flow behaviour, hence much denser plugging and core examination is required. In addition, permeability upscaling procedures need to take into account the fact that core plugs may not represent the effective permeability of the larger connected vuggy pore systems. The improved understanding of reservoir heterogeneity, the more robust reservoir characterization, and the improved history matching demonstrates that a better representation of reservoir dynamics is achieved. This provides a solid platform for designing and planning future EOR schemes.
- Europe (0.87)
- Asia > Middle East > UAE (0.28)
- North America > United States > Alaska (0.28)
- North America > United States > Texas > Permian Basin > Yeso Formation (0.99)
- North America > United States > Texas > Permian Basin > Yates Formation (0.99)
- North America > United States > Texas > Permian Basin > Wolfcamp Formation (0.99)
- (22 more...)
Streamed Workflow for Static Model Uncertainty Evaluation of Carbonate Reservoir in an Offshore Abu Dhabi Field
Al Hossani, Khalil (ADMA-OPCO, Abu Dhabi, United Arab Emirates) | Sayed, Mohamed I. (ADMA-OPCO, Abu Dhabi, United Arab Emirates) | Matarid, Tarek (ADMA-OPCO, Abu Dhabi, United Arab Emirates) | Al-Harbi, Haifa (ADMA-OPCO, Abu Dhabi, United Arab Emirates) | Walia, Samir (EMERSON-ROXAR, Abu Dhabi, United Arab Emirates) | Essam, Mohamed (EMERSON-ROXAR, Abu Dhabi, United Arab Emirates) | Kumar, Amit (EMERSON-ROXAR, Abu Dhabi, United Arab Emirates)
Abstract Defining the range of uncertainty is a crucial part in the oil field development particularly for carbonate reservoirs that have limited well data and with the absence of dynamic data. It is very important to develop an in-depth understanding of the range of uncertainty of all reservoirs parameters such as: -Structure uncertainty -Lithofacies and reservoir rock types -Static reservoir attributes population technique (Porosity, Permeability, & Water Saturation) Although outcrops and analogs are often employed to define reservoirs model parameters, it is still challenging to define and agree on the relationship between modeling parameters and their distribution ranges. This paper addresses the impact of uncertainty of different modeling parameters on the volumetric calculations and full field development scenarios starting with structure model. Various areal and vertical uncertainties were investigated to set the structure uncertainty ranges. Then, the identified depositional environment models were used as guides to set the uncertainty ranges for each lithofacies association. The reservoir rock types were directly affected by both structure and lithofacies association models. Different ranges of variations were used for each rock type within each reservoir layer to ensure capturing the lateral and vertical reservoir heterogeneity and to propose multi distribution scenarios for each reservoir tock type within non-cored intervals/areas. The petrophysical parameters were conditioned to the reservoir rock types model. So, they were directly affected by multi scenarios of RRT models. In conclusion, 20 volumetric estimates were calculated and evaluated to define the probabilistic scenarios P10, P50, and P90 that will be used to investigate the full field development scenarios.
- Asia > Middle East > UAE > Abu Dhabi Emirate > Abu Dhabi (0.52)
- Asia > Middle East > Kuwait > Jahra Governorate (0.40)
- Geology > Sedimentary Geology > Depositional Environment (1.00)
- Geology > Rock Type > Sedimentary Rock > Carbonate Rock (0.31)
- Asia > Middle East > UAE > Abu Dhabi > Arabian Gulf > Rub' al Khali Basin > Abu Dhabi Field (0.99)
- Asia > Middle East > Kuwait > Jahra Governorate > Arabian Basin > Widyan Basin > North Kuwait Jurassic (NKJ) Fields > Marrat Formation > Upper Marrat Formation (0.98)
- Asia > Middle East > Kuwait > Jahra Governorate > Arabian Basin > Widyan Basin > North Kuwait Jurassic (NKJ) Fields > Marrat Formation > Sargelu Formation (0.98)
Abstract Rock typing is a key factor in reservoir characterization studies. It is often assumed that Static Reservoir Rock Types (SRRTs) are capable of assigning multi-phase flow characteristics, such as capillary pressure and relative permeability curves to the cells of dynamic simulation models. However, SRRTs fail to capture the actual reservoir variability, due to lack of representation of wettability difference at different elevations above Free Water Level (FWL), especially in highly heterogeneous thick carbonate reservoirs. These shortcomings of SRRTs can be resolved through Dynamic Reservoir Rock Types (DRRTs), in which wettability effect is imposed on SRRTs to generate saturation functions for simulation models. This research proposes a modified DRRT approach by integrating the data from geological models and SCAL tests. First, the defined static rock types are sub-divided into sub-static rock types using either porosity or permeability frequency distribution. Second, a modified correlation equation is proposed and applied to more accurately estimate the initial water saturation versus height above FWL from well logs. Third, each sub-static rock type is further divided into a number of DRRTs by determining the capillary pressure and relative permeability curves in the oil zone from the Gas-Oil Contact (GOC) to the Dry-Oil Limit (DOL). The DRRTs are extended to the zone from DOL to the FWL by including wettability effect which would affect the curvature of the relative permeability curves but not its saturation end points, through changing the Corey exponents in the modified Brooks-Corey model. This modified DRRT approach is applied in terms of the dynamic rock typing plug-ins to generate sub-rock types from static rock types, and build a comprehensive and automatic approach to generate saturation tables for dynamic rock types that can be prospectively loaded into commercial simulators for reliable reservoir initialization, history match and prediction processes.
- North America > United States > Texas (0.47)
- Asia > Middle East > UAE > Abu Dhabi Emirate > Abu Dhabi (0.21)
- Reservoir Description and Dynamics > Reservoir Simulation (1.00)
- Reservoir Description and Dynamics > Reservoir Fluid Dynamics > Flow in porous media (1.00)
- Reservoir Description and Dynamics > Reservoir Characterization (1.00)
- Reservoir Description and Dynamics > Formation Evaluation & Management (1.00)
An Integrated Approach of Fractured Reservoir Modeling Based on Seismic Interpretations and Discrete Fracture Characterization
Gong, Bin (LandOcean Energy Services Company, Limited) | Shan, Ying (LandOcean Energy Services Company, Limited) | Tang, Jinbiao (LandOcean Energy Services Company, Limited) | Wang, Qiangqiang (LandOcean Energy Services Company, Limited) | Deng, Lin (LandOcean Energy Services Company, Limited) | Li, Junchao (Peking University)
Summary An integrated approach of fractured reservoir modeling is presented. First, the fracture density and azimuth distribution of the entire reservoir is mapped from seismic anisotropy analysis and image log calibrations. Then we apply a dynamic workflow to construct the discrete fracture model by connecting fracture elements laterally and vertically. A tetrahedral grid is then generated for detailed reservoir simulation that fully resolves the discrete fracture characterization. Finally the flow simulation is performed on an actual carbonate reservoir block in the Mideast. This study presents a systematic way of modeling and simulating fractured reservoirs.
Summary A realistic surface-to-borehole controlled-source electromagnetic (CSEM) survey was modelled to determine the sensitivity of electromagnetic fields to waterflooding in a typical Saudi Arabian carbonate oil reservoir. The reservoir saturation changes were modelled over a period of 75 years and then converted to resistivity using Archie's empirical relation. The overburden model is obtained by upscaling tri-axial resistivity logs from a test well to derive a full anisotropic profile from surface to the reservoir level. 3D Finite Difference (FD) frequency-domain modelling was performed assuming surface galvanic sources with radial and tangential polarization directions relative to the well and with receivers positioned in the reservoir. Forward modelling and inversion results indicate that electric field measurements in the borehole and the vertical component of it (Ez), in particular, may offer the necessary resolution and sensitivity to characterize reservoir saturation variations.
- North America > United States (0.48)
- Asia > Middle East > Saudi Arabia (0.15)
- North America > United States > California > San Joaquin Basin > Lost Hills Field (0.99)
- Europe > Norway > North Sea > Northern North Sea > East Shetland Basin > PL 375 > Block 34/7 > Snorre Field > Statfjord Group (0.99)
- Europe > Norway > North Sea > Northern North Sea > East Shetland Basin > PL 375 > Block 34/7 > Snorre Field > Lunde Formation (0.99)
- (13 more...)
Copyright 2012, Society of Petroleum Engineers This paper was prepared for presentation at the SPE Russian Oil & Gas Exploration & Production Technical Conference and Exhibition held in Moscow, Russia, 16-18 October 2012. This paper was selected for presentation by an SPE program committee following review of information contained in an abstract submitted by the author(s). Contents of the paper have not been reviewed by the Society of Petroleum Engineers and are subject to correction by the author(s). The material does not necessarily reflect any position of the Society of Petroleum Engineers, its officers, or members. Electronic reproduction, distribution, or storage of any part of this paper without the written consent of the Society of Petroleum Engineers is prohibited.
- Asia > Russia (0.34)
- Europe > Russia > Central Federal District > Moscow Oblast > Moscow (0.24)
- Geology > Rock Type > Sedimentary Rock (0.47)
- Geology > Geological Subdiscipline (0.46)
- Geology > Petroleum Play Type > Unconventional Play > Fractured Carbonate Reservoir Play (0.41)
- Reservoir Description and Dynamics > Unconventional and Complex Reservoirs > Naturally-fractured reservoirs (1.00)
- Reservoir Description and Dynamics > Unconventional and Complex Reservoirs > Carbonate reservoirs (1.00)
- Reservoir Description and Dynamics > Reservoir Characterization > Seismic processing and interpretation (1.00)
- Reservoir Description and Dynamics > Reservoir Characterization > Geologic modeling (1.00)
Copyright 2012, Society of Petroleum Engineers This paper was prepared for presentation at the SPE Russian Oil & Gas Exploration & Production Technical Conference and Exhibition held in Moscow, Russia, 16-18 October 2012. This paper was selected for presentation by an SPE program committee following review of information contained in an abstract submitted by the author(s). Contents of the paper have not been reviewed by the Society of Petroleum Engineers and are subject to correction by the author(s). The material does not necessarily reflect any position of the Society of Petroleum Engineers, its officers, or members. Electronic reproduction, distribution, or storage of any part of this paper without the written consent of the Society of Petroleum Engineers is prohibited. Permission to reproduce in print is restricted to an abstract of not more than 300 words; illustrations may not be copied. The abstract must contain conspicuous acknowledgment of SPE copyright. Abstract This paper presents the successive modeling solutions used to estimate the performance under primary and secondary recovery of the Kharyaga field. Kharyaga object 2 is characterized by different zones of heterogeneities and reservoir type: while platform margin is fractured and karstified, no karstic features are identified in the platform interior, transition zones seems the most complex.
- Europe > Russia > Northwestern Federal District > Nenets Autonomous Okrug (0.91)
- Europe > Russia > Central Federal District > Moscow Oblast > Moscow (0.24)
- Geology > Structural Geology (1.00)
- Geology > Geological Subdiscipline (1.00)
- Geology > Rock Type > Sedimentary Rock > Carbonate Rock (0.93)
- Geophysics > Seismic Surveying (1.00)
- Geophysics > Borehole Geophysics (0.68)
- North America > United States > New Mexico > San Juan Basin > Media Field (0.99)
- North America > United States > New Mexico > Permian Basin > Double Field (0.99)
- Europe > Russia > Northwestern Federal District > Nenets Autonomous Okrug > Timan-Pechora Basin > Pechora-Kolva Basin > Kharyaga Licence > Kharyaginskoye Field (0.99)
- (4 more...)