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Abstract A typical fractured carbonate reservoir introduces a tremendous challenge to upscaling of single- and multi-phase flow. The complexity comes from both heterogeneous matrix and fracture systems where separation of scales is very difficult, if not impossible. The mathematical upscaling techniques, based on representative elementary volume, must therefore be replaced by a more realistic geology-based approach. In the case of multi-phase flow, an evaluation of the main forces acting during oil recovery must also be performed. A matrix sector model from a highly heterogeneous carbonate reservoir is linked to different fracture realizations in dual continuum simulations. An integrated iterative workflow between the geology based static modelling and dynamic simulations is used to investigate the effect of fracture heterogeneity on multi-phase fluid flow. Heterogeneities at various scales, from diffuse fractures to sub-seismic faults, as well as fracture barriers, are considered. The diffuse fracture model is built based on facies and porosity from the matrix model together with core data, image log data and data from outcrop analogues. The sub-seismic fault model is conceptual and based on analysis of outcrop analogue data. Fluid flow simulations are run for both single-phase and multi-phase flow, gas and water injection. Better understanding of fractured reservoirs behaviour is achieved by incorporating realistic fracture heterogeneity into the geological model and analysing the dynamic impact of fractures at various scales. In the case of diffuse fractures, the heterogeneity effect can be captured in the upscaled model. The sub-seismic faults, however, must be explicitly represented, unless the sigma factor is included in the upscaling process. A local grid refinement approach is applied to demonstrate explicit fractures in large scale simulation grid. This study provides guidelines to how to effectively upscale a heterogeneous fracture model and still capture the heterogeneous flow behaviour.
- Asia > Middle East (0.46)
- Europe (0.28)
- Well Completion > Hydraulic Fracturing (1.00)
- 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)
- (4 more...)
Integrated Reservoir Modeling for Water Flood Development in a Heterogeneously Fractured Carbonate Reservoir, North Oman
Hillgartner, Heiko (Petroleum Development Oman LLC) | Paino, Wan Faisal (Petroleum Development Oman LLC) | Hadhrami, Fahad (Petroleum Development Oman LLC) | Sinani, Ibrahim (Petroleum Development Oman LLC) | Mukhopadhyay, Arunesh (Petroleum Development Oman LLC) | Habsi, Ranya (Petroleum Development Oman LLC) | Naamani, Ali (Petroleum Development Oman LLC) | Subhi, Wahab (Petroleum Development Oman LLC) | Heyden, Frederic Vander (Petroleum Development Oman LLC)
Abstract The carbonate reservoir in question is located in the northwest of the Sultanate of Oman and was developed first in depletion mode since 1970. From the year 2000 until today a horizontal water flood scheme has been implemented. The reservoir is made up of 2 carbonate layers of 27 and 13 meters thickness intercalated with several meter thick shale layers. They form the deepest reservoir layers of the Cretaceous Natih Formation. The reservoir layers are composed of laterally continuous, microporous, low permeability (5-10mD) limestone that is interpreted to be heterogeneously but overall sparsely fractured. The implemented water flood in this field is considered to be well behaved with a stable oil production and low water cuts of around 20 to 25%. An integrated field study was carried out for a planned horizontal infill development. The main objective was to obtain a representative set of static and dynamic models that match historic production. One of the principal challenges was the unknown impact of fracturing and faulting on the intensified water flood development in the reservoir layers and on the potential vertical communication within and with overlying reservoir layers. Seismic, geological, petrophysical, and reservoir data were integrated with drilling and production information to produce a detailed matrix and fracture description of the reservoir. Several iterative workflows that included numerous feedback loops with reservoir simulation results were applied to achieve an appropriate history match and confidence into the predictive capabilities of the reservoir model and the simulation forecasts. The main achievements of the applied workflow are a major reduction of the uncertainties related to the impact of faults and fractures on reservoir behavior. Key was the close integration of simulation results of the dual porosity permeability model and field data. The modeling workflow of the matrix and fracture models and their implementation in the reservoir simulator were optimized in such a way that uncertainty evaluation was entirely handled in the simulator and simulation times were reduced significantly. This study has clearly shown that even in reservoirs that appear to be relatively simple and well behaving with respect to the chosen development option may require a much deeper level of understanding and may reveal significant complexities. In the presented case the reservoir formerly believed to be "simple matrix dominated reservoir" shows a significant heterogeneity in fracturing across the area of interest. Only detailed understanding after comprehensive data integration, construction of a dedicated continuous fracture model and a dual porosity permeability simulation model allowed achieving reliable predictions on reservoir behavior. The study has led to improved well planning and well and reservoir management practices in response to sudden increase in water production. The applied workflows may serve as an example for comparable carbonate reservoirs with apparent sparse fracturing that, however, may impact water flood development.
- Geology > Structural Geology (1.00)
- Geology > Geological Subdiscipline > Stratigraphy (1.00)
- Geology > Rock Type > Sedimentary Rock > Carbonate Rock (0.88)
- Geology > Rock Type > Sedimentary Rock > Clastic Rock > Mudrock > Shale (0.55)
- Geophysics > Borehole Geophysics (1.00)
- Geophysics > Seismic Surveying > Seismic Interpretation (0.46)
- 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 Simulation > Evaluation of uncertainties (1.00)
- (4 more...)
- Information Technology > Modeling & Simulation (1.00)
- Information Technology > Data Science > Data Integration (0.34)
- Information Technology > Artificial Intelligence > Representation & Reasoning > Information Fusion (0.34)
Reserves Estimation Uncertainty in a Mature Naturally-fractured Carbonate Field Located in Latin America
Vega Riveros, Gina Luz (Petroleum Consultant Company) | Saputelli, Luigi Alfonso (Hess Corporation) | Perez, Jose Leonardo Patino (Halliburton) | Chacon, Alejandro (Halliburton) | Solis, Romeo (Qatar Petroleum)
Abstract This paper describes a case study combining more frequently used tools in the petroleum industry, such as volumetric analysis with Monte Carlo Simulation and Material Balance, to improve performance predictions in the carbonate mature fields offshore. Quantifying the uncertainties in original oil in place (OOIP) estimates can support development and investment decisions for individual reservoirs. In the early life of a reservoir, the well data is largely uncertain. Probabilistic estimates are commonly generated prior to significant production from a carbonate mature field by combining volumetric analysis with the Monte Carlo method. The Monte Carlo method was used to compute the oil in place using static reservoir properties, such as petrophysical parameters, which always involve a magnitude of uncertainty and, as such, should be treated as random variables with distinct probability distributions. To assess the profitability of the development project, it was necessary to use material balance for the field. Material balance evaluation has been identified as a useful tool for initially establishing connected hydrocarbon volume in place and for identifying reservoir drive mechanisms. This tool is often considered more accurate than volumetric methods, since the volumetric methods are based on dynamic reservoir data such as pressure and production, and thus can be applied only after the reservoir has produced for a significant period of time. The outcome of the Monte Carlo simulation was a range of reserve values with their associated probabilities of P10, P50, and P90. A commercial material balance software was used to carry out a combination of the analytical and graphical methods establishing the correct material balance model, thereby adding confidence in the obtained results for reserves in the field. OOIP was found to be approximately 235 to 245 MMSTB, of which ~21% is stored in the matrix system. During the execution of the project, the combination of methods can reduce the non-uniqueness of the material balance solution. Material balance can reduce the uncertainty in the range estimates, since they are based on observed performance data. Base case prediction forecasts only recovered 19% of OOIP, or an additional 9% from current recovery. This is in agreement with the references of similar fields. Based on 40-year prediction forecasts, an additional ~72.6 to 98 MMSTB of oil-equivalent reserves can be generated with an additional capital expenditure (CAPEX) of 450 to 600 MM$ for water or gas injection facilities and 10 to 14 wells, leading to a recovery factor of ~40.9 to 46.6 of OOIP. Introduction Field development planning is traditionally a sequential process; decisions are often segmented and disconnected. Typically, reservoir engineers model reservoir response to the bottom hole, production engineers model the whole wellbore to the well head, and process engineers model the surface facilities from the well head to the tank (Saputelli et al. 2002). For the above reasons, project results often deviate from the project plan. In the building of field development plans, in-situ hydrocarbon reserves represent a key uncertainty to be analyzed. Because of poor predictability in hydrocarbon reserves, surface facilities may remain sub-utilized, a reservoir's full potential may not be obtained, and field economics may not reach peak performance. Field development decisions must be made despite uncertainties in hydrocarbon reserves. The heterogeneity of information and the complexity of current hydrocarbon assets require an iterative approach to identify the best opportunities.
- South America (1.00)
- North America > United States (1.00)
- Asia > Middle East (0.68)
- 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 Simulation > Evaluation of uncertainties (1.00)
- (2 more...)
Modeling Naturally Fractured Tight Carbonate Reservoirs – A Case Study
Chakraborty, Subrata (Schlumberger) | Narahari, Srinivasa Rao (Kuwait Oil Company(KOC)) | Al-Ajmi, Neama Hussain (Kuwait Oil Company(KOC)) | Al-Ashwak, Samar (Kuwait Oil Company(KOC)) | Kidambi, Vijaya Kumar (Kuwait Oil Company(KOC)) | Pattnaik, Chinmaya (Kuwait Oil Company(KOC)) | Stelzer, Hermann (Schlumberger)
Abstract Kuwait Oil Company (KOC) is engaged in an early phase of development of a giant, tight, fractured carbonate play within the State of Kuwait, spread over a large area covering six fields. The producing reservoirs belong to the geological Formations of Toarcian to Tithonian age. Some reservoirs are characterized by very low porosity and permeability and productivity of these reservoirs is driven by the natural fracture system. This paper described the approach followed in developing a 3D fracture model for these reservoirs. Carefully planned data acquisition resulted in a rich suite of dataset consisting of image logs, conventional cores covering the target pay zones in a number of wells. Analysis of these data gave a clear understanding about fracture orientation, density, aperture, and other fracture parameters. Special 3D seismic processing was carried out to derive a volume curvature attribute, which was able to detect and identify the fracture corridors away from the wells. Structural geological analysis resulted in an understanding of the tectonic history of the area, which helped in genetically relating the identified fracture orientations with the structural evolution. A discrete fracture network was developed for these reservoirs combining the well and seismic attribute data. Parameters like aspect ratio, orientation and aperture of fractures was assigned to different fracture sets based on this analysis. The apertures were corrected for the present day stress effect based on the borehole breakout data. This fracture model was upscaled into the 3D geological model to get the fracture porosity and the permeability tensors. The fracture model was validated by history matching pressure build up and production data and was used for dynamic flow simulation studies for the field development planning.
- Geology > Structural Geology (1.00)
- Geology > Rock Type > Sedimentary Rock (1.00)
- Geology > Geological Subdiscipline > Geomechanics (1.00)
- Geology > Geological Subdiscipline > Stratigraphy (0.95)
- Well Completion > Hydraulic Fracturing (1.00)
- 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)
- (4 more...)
Abstract Horizontal wells provide increased reservoir contact than conventional vertical wells but present another set of production challenges particularly with respect to imbalanced fluid inflow along the wellbore. This paper will describe the importance of wellbore and reservoir characterization, modelling and practical operational experiences to maximize recovery in a carbonate environment using logging while drilling (LWD) measurements to design reliable and effective completion equipment to manage production. Due to the fractured nature of carbonates and high heterogeneity contrast with the matrix, it is imperative to balance inflow and delay the production of more mobile fluids through the installation of passive inflow control devices (ICD) and swellable packers. Near wellbore steady state and numerical reservoir simulation is particularly important for preliminary design and justification of completion technology. The latter can indicate regions of by-passed oil and areas of high water saturation providing horizontal well infill opportunities. The analysis of real time LWD is essential for well placement but also the characterization of the near wellbore to identify areas of high fracture density and where fluid losses have occurred, to design an appropriate completion tally to maximize production. The availability of adjustable ICDs at the wellsite offers the opportunity to perform this task to fine tune the lower completion design before running in hole. The modelling workflow and operational procedures of optimizing well placement and ICD completion design will be described through carbonate field installations.
- Asia (1.00)
- Europe (0.93)
- North America > United States > Texas (0.28)
- Oceania > Australia > Western Australia > North West Shelf > Carnarvon Basin > Dampier Basin > WA-209-P > Stag Field (0.99)
- Oceania > Australia > Western Australia > North West Shelf > Carnarvon Basin > Dampier Basin > WA-15-L > Stag Field (0.99)
- Africa > Nigeria > Gulf of Guinea > Niger Delta > Niger Delta Basin > OML 133 > Erha Field (0.99)
Approximate Simulation of Complex Reservoirs by Using Commercial Simulator
Peng, Xiaolong (State Key Laboratory of Oil and Gas Reservoir Geology and Exploitation, Southwest Petroleum University) | Liang, Baosheng (Chevron ETC) | Du, Zhimin (State Key Laboratory of Oil and Gas Reservoir Geology and Exploitation, Southwest Petroleum University)
Abstract Complex heterogeneous reservoir exhibits special characteristics, such as multiple storage types, wide range of storage sizes, complicated storage combinations, and various flow behaviors. Most fracture-matrix dual-porosity models in current simulators have difficulties to capture the complicated fluid flow in those complex reservoirs and are not well suitable to be used directly. Some numerical and experimental studies are in process but they have not been available in field practice yet. This paper considers various impact complex reservoir characteristics and proposes an approximate numerical simulation method on the basis of dual-porosity theory and current simulators. The simulators are extended to more accurately model flow behaviors in the complex reservoirs. Several steps developed in this paper are as follows: First, reservoir storage is categorized into continuous and non-continuous media according to storage scale characteristics, distribution and intensity. In general, small cavities, small fractures, and pores in the rock are continuous while large-scale fractures, big cavities or caves are non-continuous. Second, an M-medium model is determined and applied to the continuous region which has N storage types. M is less than or equal to N. The determination of N is illustrated through a dual-porosity model: a continuous medium with two different storage types (such as vug and fracture) or different scales should be treated by a dual-porosity model only if the direction of the flux is ignorable. A new calculation for the flux transfer is then derived for such fracture-vug dual-porosity system. On the other hand, if the flux is directional, a single-medium model is sufficient to the reservoir simulation. Third, flow in a filled non-continuous medium is described by Darcy's law. Free flow in large unfilled cavities or caves follows Navier-Stokes equation and an approximate approach to using Darcy flow simulation is provided. The determination of the critical value for the cavity permeability is illustrated through a cross-sectional model. Lastly, the complex fracture-vug reservoir is simplified into four types of dual-medium models. The proposed method is applied to a naturally fractured carbonate reservoir with cavities in the Tarim Basin in China. The simulation results match production data and meet the accuracy required in engineering.
- North America > United States > Texas (1.00)
- Asia > China (1.00)
- 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...)
- 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 Simulation (1.00)
- (3 more...)
Steam Assisted GOGD in Light Oil Reservoir - Pre-EOR Cold Daseline Importance and How We Achieved It
Saluja, Jasmeet Singh (Petroleum Development Oman) | Hamm, Ron (Petroleum Development Oman) | al Ghafri, Salah (Petroleum Development Oman) | al Gharbi, Mohammed (Petroleum Development Oman) | Diri, Muhammad (Petroleum Development Oman)
Abstract Steam Assisted Gas-Oil Gravity Drainage (SAGOGD) trial is planned for a limited area of a giant producing light oil field in Oman. Oil production from this oil-wet fractured carbonate reservoir commenced in 1967, and recovery factor currently stands at approximately 20%. The SAGOGD process in a light oil fractured reservoir is complex and is comprised of numerous recovery mechanisms, with a number of these being uncertain and poorly understood. Very little world analogue data is available [1], and that, combined with large recovery process uncertainties make this ‘large pilot scale’ Phase 1 essential to mitigate the downside risk in a full-field development. During Phase-1 it is planned to inject 2000t/d of steam by means of 4 vertical steam injectors. Oil, gas and condensed steam will be produced by 7 horizontal producers and 5 vertical back-up producers. The magnitude of the SAGOGD production response is highly uncertain. Having the capability to accurately measure the incremental oil production response over this wide uncertainty range was considered to be a key success factor for the Phase 1 project. To accurately measure the incremental response required that a ‘no steam’ production response could be confidently projected into the future for a minimum of two, and up to five years. This task was made considerably more complex by the fact that historical GOGD well production profiles were often relatively unstable. This paper describes the work carried out within PDO to ensure that one of the key Phase 1 success criteria – that being to measure the incremental oil due to SAGOGD – can be achieved over a primary evaluation period of two to five years. The discussion will include a description of efforts linked to optimization of cold GOGD performance (optimum oil rim management), well production stabilization (via installation of new production control hardware) and accurate measurement of total and individual well production levels (dedicated bulk and well-test facilities), and how this all came together to yield a stable cold production baseline which could be confidently projected into the future.
- Asia > Middle East > Oman (0.36)
- North America > United States > Oklahoma > Beaver County (0.24)
- Reservoir Description and Dynamics > Unconventional and Complex Reservoirs > Naturally-fractured reservoirs (1.00)
- Reservoir Description and Dynamics > Reservoir Simulation (1.00)
- Reservoir Description and Dynamics > Improved and Enhanced Recovery (1.00)
- (2 more...)
- Information Technology > Sensing and Signal Processing (0.47)
- Information Technology > Communications > Networks > Sensor Networks (0.47)
Abstract Anisotropy and heterogeneity in reservoir properties introduce challenges during the development of hydrocarbon reservoirs in naturally fractured reservoirs. In reservoir simulations, grid-block properties are frequently assigned to obtain reasonable history matches. Even then, accuracy with regard to some aspects of the performance such as water or gas cuts, breakthrough times, and sweep efficiencies may be inadequate. In some cases, this could be caused by the presence of substantial flow through natural fractures. In this work the fracture characterization and modeling was performed in a highly fractured carbonate reservoir in SW Iran. It was observed that reservoir simulation based on the generated fracture model present a more reasonable history matching of the production. The study indicates that NE-SW is the dominant orientation of critically stressed fractures that are most problematic for gas/water breakthrough. The primary objectives of this study are:construct a fracture 3D model to be used in reservoir simulation and distinguish the most problematic fractures in water/gas breakthrough. The steps of this study are as follows:Constructing the 3D geological framework of the reservoir. Identifying and characterizing natural fractures at the well level using borehole images. Generating the 3D-stochastic model of discrete fracture network (DFN), incorporating image log data with outcrop analogies studies in the context of buckle folding mechanism. Scaling up the fracture model with integration of well test results Running reservoir simulation based on the scaled-up fracture model to validate the model and observe the history matching Performing critically stressed fractures (CSF) analysis to distinguish problematic fractures. Introduction Naturally fractured reservoirs (NFRs) comprise a large portion of carbonate reservoirs in Middle East. Numerous challenges dealing with fracture system behavior incorporated with natural complexity of carbonates present a challenging environment for geoscientists and reservoir engineers to characterize and predict such reservoirs. However, conventional dual porosity simulations of fractured reservoirs are usually based on frequently assigning values to fracture properties to obtain reasonable history match for production of the field. This creates a big source of uncertainty in predicting the reservoir behavior and often results in frequent surprises during development. Comprehensive characterization coupled with modeling of fracture network is the key for understanding the performance of NRFs in particular carbonates ones.
- Geology > Geological Subdiscipline > Geomechanics (1.00)
- Geology > Rock Type > Sedimentary Rock (0.94)
- Geology > Geological Subdiscipline > Economic Geology > Petroleum Geology (0.67)
- (2 more...)
- Geophysics > Borehole Geophysics (1.00)
- Geophysics > Seismic Surveying (0.90)
- Asia > Middle East > Iraq > Zagros Basin (0.99)
- Asia > Middle East > Iran > Zagros Basin (0.99)
- 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 Simulation (1.00)
Abstract The North Kuwait Jurassic Complex (NKJC) consists of six fields with four identified reservoirs in the naturally fractured Jurassic carbonate section. An integrated model incorporating seismic, geological, petrophysical, and engineering data is built to estimate the hydrocarbon volumes and provide multiscenario production forecasts for the NKJC. Water saturation is populated in the static (fine-grid) model using a saturation height function (SHF), which is a continuous function of porosity and height above free-water level (HAFWL). The SHF is equivalent to a capillary pressure (at reservoir conditions), which is a function of porosity and water saturation. Capillary pressure curves based on the SHF are used to initialize water saturation in the dynamic (upscaled) model. Given the fact that reservoir simulators cannot handle capillary pressure curves as continuous functions of porosity, discretization of the porosity-dependent capillary pressure function was performed. For this purpose, 15 capillary pressure curves (corresponding to 15 porosity categories) were used. Populating initial water saturation in the dynamic model using the SHF (or the equivalent capillary pressure curves) results in a substantial discrepancy in terms of water saturation between the static model and the dynamic model. The discrepancy is mainly because of the nonlinear dependency of the SHF versus porosity and the averaging of HAFWL. Upscaling tends to eliminate the high and low porosity values in favor of the average porosity, which leads to substantial changes in the resulting water saturation. Because the calculated water saturation is highly dependent on the porosity and HAFWL, upscaling results in a mismatch between static and dynamic models in terms of hydrocarbon estimates. To overcome this problem, the initial water saturation in the simulation model is populated using the pore volume-weighted, upscaled water saturation from the static model. The endpoint-scaling functionality in the simulator is then used to modify the discrete set of capillary pressure curves to support the provided initial water saturation. Results show that the correction of the capillary pressure curves needed by the simulator to support the provided initial water saturation values is relatively minor while full consistency between the static and dynamic models in terms of water saturation is obtained. Background The North Kuwait Jurassic Complex (NKJC) consists of six fields with four potential reservoirs (Najmah/Sargelu, Upper, Middle, and Lower Marrat) in naturally fractured carbonate formations. The fields have been subdivided into 12 major areas based on fault boundaries supported by a combination of variations in fluid composition, initial pressures, and free water level estimates. With the four producing formations, there are potentially 48 separate compartments (segments) in the complex. The reservoirs contain multiple fluid types at near-critical conditions with an average temperature of 275°F, an initial reservoir pressure averaging 11,000 psia, and saturation pressures ranging from 4,300 to 6,200 psi.
- Asia > Middle East > Kuwait > Jahra Governorate > Arabian Basin > Widyan Basin > North Kuwait Jurassic (NKJ) Fields > Marrat Formation > Upper Marrat Formation (0.97)
- Asia > Middle East > Kuwait > Jahra Governorate > Arabian Basin > Widyan Basin > North Kuwait Jurassic (NKJ) Fields > Marrat Formation > Sargelu Formation (0.97)
- 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 Simulation > Scaling methods (1.00)
- (3 more...)
Abstract Understanding production behavior particularly from fractured carbonates has always been a challenge. The difficulty stems from the secondary porosity and permeability developments in carbonates in conjunction with the seemingly haphazard fracture presence in the midst of rapid and erratic facies changes sometimes within short distances. To make matters worse the spatial connectivity of these fractures complicates completion, pressure maintenance and improving sweep strategies. Therefore it is paramount to understand and characterize the fractured conduits and account for their importance in the overall development of the field. This paper discusses a systematic step-by-step methodology to build a geologic realization for a fractured reservoir and conduct dynamic simulations to calibrate and forecast various development scenarios. The methodology encompasses geo-scientific work, engineering analysis, production diagnostics and reservoir simulation. Classic clustering analysis is used to augment results of production diagnostics to capture the effects of fracture dominated flow. Further, material balance utilizes early production and pressure history, during both undersaturated and saturated conditions, to provide bounds of in-place fluids. Petrophysical work analyzes available well logs to obtain matrix attributes and classify reservoir and non-reservoir types. The static model devises empirical transforms to distinguish various facies types. The facies types are stochastically populated in the inter-well region. A possible realization of the reservoir based on total-property approach is constructed. The reservoir model is then calibrated based on 25 years of production and some pressure history. Finally, various development scenarios are investigated. The observations of clustering analysis is discussed and tied to the production behavior. The insights gained are shown to enhance calibration process. The integrated approach is demonstrated to unlock various uncertainties about in-place and recoverable reserves. Significant contributions are:Clustering analysis in conjunction with production diagnostics to reveal the nature of the fractures Weigh various development scenarios to unlock the myths of stereotypical development pattern A way to learn more about the reservoir architecture and resident fluid movements to screen for upside potential
- Reservoir Description and Dynamics > Reservoir Simulation (1.00)
- Reservoir Description and Dynamics > Formation Evaluation & Management (1.00)
- Data Science & Engineering Analytics > Information Management and Systems (1.00)
- (6 more...)