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Results
Natural petroleum gases contain varying amounts of different (primarily alkane) hydrocarbon compounds and one or more inorganic compounds, such as hydrogen sulfide, carbon dioxide, nitrogen (N2), and water. Characterizing, measuring, and correlating the physical properties of natural gases must take into account this variety of constituents. A dry-gas reservoir is defined as producing a single composition of gas that is constant in the reservoir, wellbore, and lease-separation equipment throughout the life of a field. Some liquids may be recovered by processing in a gas plant. A wet-gas reservoir is defined as producing a single gas composition to the producing well perforations throughout its life.
- Reservoir Description and Dynamics > Unconventional and Complex Reservoirs > Gas-condensate reservoirs (1.00)
- Reservoir Description and Dynamics > Reservoir Simulation (1.00)
- Reservoir Description and Dynamics > Reservoir Characterization (1.00)
- (6 more...)
- Information Technology > Knowledge Management (0.40)
- Information Technology > Communications > Collaboration (0.40)
Abstract A methodology has been developed that, in conditions of limited geological and production data, ensures the integration of petrophysical, geological, and hydrodynamic models as components of a permanent 3D model, establishing physical relationships between parameters that describe the entire system. In the proposed method, the modelling is based on the results of the interpretation of continuous shale volume and porosity curves. Based on the analysis of core data, the multi-vector physical correlations with other parameters are made. To distinguish the reservoirs and non-reservoirs, the cut-off values of shale volume are defined; to exclude tight reservoirs with no filtration, the cut-off values of porosity are set. Using the Winland R35 method the radius of the pore throat is computed, allowing dividing the reservoirs into classes. For each class of reservoirs, the permeability vs porosity dependence is determined, and the Wright-Woody-Johnson method allows deriving equations for the bound water content. A system of configured workflows has been developed and allows automating re-modelling and simplifying its history matching. This technique was successfully applied to several 3D models of gas condensate fields, which, with a significant drilling level on the areas and a long development history, are characterized by limited geological and production data. Workflows System together with the proposed approach allowed simplifying the history matching process by splitting it into several stages. At each stage, depending on the type of input data, various parameters were matched (production, reservoir and wellhead pressures, etc.). Due to cross-functional correlation of all components, the model has significantly reduced the uncertainty parameters and allowed a detailed history matching of the development history for the entire well stock. The results obtained were tested by several geological and technological measures, including drilling new wells, and showed high convergence with the forecast indicators. The proposed approach to modelling and history matching in conditions of limited geological and production data allows: –ensuring integration and correlation of petrophysical, geological, and hydrodynamic models as components of a permanent 3D model; –automating and simplifying the modelling, history matching, and updating a model; –improving the quality of parameters’ matching results.
- Reservoir Description and Dynamics > Unconventional and Complex Reservoirs > Gas-condensate reservoirs (1.00)
- Reservoir Description and Dynamics > Reservoir Simulation > History matching (1.00)
- Reservoir Description and Dynamics > Reservoir Fluid Dynamics > Flow in porous media (1.00)
- (3 more...)
Abstract Hydrocarbon reservoir performance forecasting is an integral component of the resource development chain and is typically accomplished via reservoir modeling using either numerical or analytical methods. Although complex numerical models provide rigorous means of capturing and predicting reservoir behavior, reservoir engineers also rely on simpler analytical models to analyze well performance and estimate reserves when uncertainties exist. Arps, for example, empirically demonstrated that certain reservoirs may decline according to simple, exponential, hyperbolic, or harmonic relationships; such behavior, however, does not extend to more complex scenarios, such as multi-phase reservoir depletion. Due to this limitation, an important research area for many years has been to transform the equations governing flow through porous media in such a way as to express complex reservoir performance in terms of closed analytical forms. In this work, it is demonstrated that rigorous compositional analysis may be coupled with analytical well performance estimations for reservoirs with complex fluid systems, and that the molar decline of individual hydrocarbon fluid fractions can be expressed in terms of rescaled-exponential equations for well performance analysis. This work demonstrates that, by the introduction of a new partial pseudo-pressure variables, it is possible to predict the decline behavior of individual fluid constituents of a variety of gas condensate reservoir systems characterized by widely varying richness and complex multi-phase flow scenarios. A new four-region flow model is proposed and validated to implement gas-condensate deliverability calculations at late times during variable bottomhole pressure production. Five case studies are presented to support each of the model capabilities stated above and validate the use of liquid-analog rescaled-exponentials for the prediction of production decline behavior for each of the hydrocarbon species.
- Asia > Middle East (0.93)
- North America > United States > Texas (0.46)
- Reservoir Description and Dynamics > Unconventional and Complex Reservoirs > Gas-condensate reservoirs (1.00)
- Reservoir Description and Dynamics > Reservoir Simulation (1.00)
- Reservoir Description and Dynamics > Reservoir Fluid Dynamics > Flow in porous media (1.00)
- (5 more...)
Pressure Build-Up Test Interpretation Studies: Models, Numerical Simulation, and Field Test in the Huabei Oilfield
Miao, Y.. (China University of Petroleum) | Li, X.. (China University of Petroleum) | Zhou, Y.. (China University of Petroleum) | Li, H.. (Texas A&M University) | Shi, J.. (China University of Petroleum) | Chen, Y.. (China University of Petroleum)
Abstract Accurate pressure build-up test interpretation technologies for both conventional and unconventional reservoir development have been highly applied in oil and gas industries in recent years. However, for the late development stage of wells, current well test interpretation methods lose their accuracy to characterize fluid flow behavior and fracture properties etc. due to the complex underground situation and interference among adjacent wells. Novel pressure build-up test interpretation methods should be developed with the incorporation of these effects. We developed a novel model to interpret formation pressure and formation physical properties, during the process of pressure build-up test, by incorporating stress interference among adjacent wells and two-phase flow of oil/water directly into the model. Trial approach was utilized to iteratively correct average formation pressure and permeability of oil and water phase, depending on the complexity of well interference systems. A simulation was developed based on this semi-analytical model which is capable of interpreting formation pressure and formation physical properties during the process of pressure build-up with much higher accuracy compared with traditional methods. A numerical simulation in Eclipse was utilized to validate our model. Our interpretation results, including formation pressure, skin factor and permeability etc., are in fair agreement with the numerical simulation. We applied our model to conduct pressure build-up interpretation tests for testing wells in the Huabei Oilfield, and the precision of our model can reach up to 35.15% which has greater accuracy compared with traditional methods. This novel model exhibits high efficiency and accuracy for pressure build-up test interpretation for the case with interference among adjacent wells and oil and water two-phase flow. This work provides an effective framework for pressure build-up test interpretation in fractured reservoir development.
- Oceania > Australia > Queensland > Surat Basin (0.99)
- Oceania > Australia > New South Wales > Surat Basin (0.99)
- Asia > China > Hebei > Bohai Basin > Huabei Field (0.99)
- 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 > Drillstem/well testing (1.00)
Any reservoir simulator consists of n m equations for each of N active gridblocks comprising the reservoir. These equations represent conservation of mass of each ofn components in each gridblock over a timestep Δt from tn to tn 1 . The firstn (primary) equations simply express conservation of mass for each of n components such as oil, gas, methane, CO2, and water, denoted by subscript I 1,2,…,n. In the thermal case, one of the "components" is energy and its equation expresses conservation of energy. An additional m (secondary or constraint) equations express constraints such as equal fugacities of each component in all phases where it is present, and the volume balanceSw So Sg Ssolid 1.0, whereS solid represents any immobile phase such as precipitated solid salt or coke. There must be n m variables (unknowns) corresponding to these n m equations. For example, consider the isothermal, three-phase, compositional case with all components present in all three phases.
- Europe > United Kingdom (1.00)
- Europe > Norway (1.00)
- North America > United States > Texas (0.94)
- (2 more...)
- Geology > Structural Geology > Fault (1.00)
- Geology > Geological Subdiscipline > Geomechanics (1.00)
- Geology > Rock Type > Sedimentary Rock > Clastic Rock (0.67)
- Geophysics > Seismic Surveying (0.67)
- Geophysics > Time-Lapse Surveying > Time-Lapse Seismic Surveying (0.67)
- South America > Argentina > Patagonia > Golfo San Jorge Basin (0.99)
- North America > United States > California > San Joaquin Basin > Lost Hills Field (0.99)
- North America > United States > Alaska > North Slope Basin > Prudhoe Bay Field (0.99)
- (20 more...)
- Well Drilling > Wellbore Design > Wellbore integrity (1.00)
- Reservoir Description and Dynamics > Unconventional and Complex Reservoirs > Gas-condensate reservoirs (1.00)
- Reservoir Description and Dynamics > Reservoir Simulation > Streamline simulation (1.00)
- (21 more...)
Abstract Reservoir studies, including preparation of field development plan, are processes typically dominated by time constraints. In general, reservoir studies consist in multiple geoscience activities integrated to build a fine geological model that eventually leads to an upscaled numerical model suitable for history matching and forecast simulations. In the simulation stage, the quality and effectiveness of the activity is highly dependent on the computational efficiency of the numerical model. This is particularly true for complex, supergiant carbonate reservoirs. Often, even with today's simulators, upscaling is still needed and simplifications can be implemented to allow computationally intensive history matching and risk analysis workflows. This paper provides some real field examples where these issues were faced and successfully managed, without applying further simplifications to the geological concept of the model: principles of reservoir simulations and common sense reservoir engineering were used to adjust properties of the model and then speed-up numerical simulation. Tuning included a combination of various solutions, such as deactivating critical cells whenever possible, calibrating convergence and time stepping control, tweaking field management to prevent instability in the computation, optimization of number of cores and cells split among cores to optimize load balancing and scalability. These solutions were used on two super-giant carbonate fields, a triple porosity (matrix, karst and fractures) undersaturated light oil reservoir and a supercritical gas and condensate reservoir. The former field was described using an upscaled model of about 700,000 active cells and a dual porosity - dual permeability formulation; the latter was described by a relatively coarse model of about 400 thousand active cells using a single porosity formulation. Large speed-up, up to five times with respect to reference simulations, was achieved without simplifying the geology and losing accuracy perceivably. Benefits were achieved for both conventional and high-resolution simulators.
- Geology > Rock Type > Sedimentary Rock (0.48)
- Geology > Geological Subdiscipline (0.34)
- Reservoir Description and Dynamics > Unconventional and Complex Reservoirs > Gas-condensate reservoirs (1.00)
- Reservoir Description and Dynamics > Unconventional and Complex Reservoirs > Carbonate reservoirs (1.00)
- Reservoir Description and Dynamics > Reservoir Simulation > History matching (1.00)
- (6 more...)
Abstract In the presented work an uncertainty analysis was applied for the unique multilayer field with a complex structure. Main uncertainty parameters as a structural mapping, gas-water contact, petrophysical correlations, lithology distribution were assessed for an influence on reserves and gas production. Much attention was directed to the calculation of structural mapping uncertainties. They were assessed using stochastic modeling – generation of structure error map based on estimated error from seismic data. Each map consists of low and high frequency maps depending on distance from exploration wells. Stochastic algorithm SGS (sequential Gaussian simulation) was performed for the maps construction. Results of the work were applied to determine the influence of the main uncertainty parameters on the production forecast. This article is dedicated to one of the company's unique oil and gas fields with a complex geological structure, which is in preparation for trial production stage. Productivity is determined in 32 layers (109 accumulations). The aim of this work is to assess the impact of main uncertainties on forecast level of hydrocarbon production and geological reserves of the field.
- Geophysics > Seismic Surveying > Surface Seismic Acquisition (0.46)
- Geophysics > Seismic Surveying > Seismic Processing (0.31)
- Reservoir Description and Dynamics > Unconventional and Complex Reservoirs > Gas-condensate reservoirs (1.00)
- Reservoir Description and Dynamics > Reservoir Simulation (1.00)
- Reservoir Description and Dynamics > Reservoir Fluid Dynamics > Flow in porous media (1.00)
- (3 more...)
Development History Case of a Major Oil-Gas-Condensate Field in a New Province
Grinchenko, V. A. (Tyumen Petroleum Research Centre) | Anuryev, D. A. (Tyumen Petroleum Research Centre) | Miroshnichenko, A. V. (Tyumen Petroleum Research Centre) | Gordeev, Y. I. (VerkhnechoskNefteGas) | Lazeev, A. N. (NK Rosneft)
Eastern Siberia is currently an insufficiently explored area with complex conditions, on the other hand it has a high hydrocarbon potential. A number of oil and gas fields have been discovered in the region already. Vigorous exploration and appraisal works are performed there. However, bringing new fields into development is impeded by multiple factors including complex natural climatic conditions, insufficient exploration of the region, significant distances between fields within the area, absence of transport and industrial infrastructure, and finally complex geologic-and-physical reservoir characteristics. All above factors require nonstandard approaches to field development design and engineering solutions for effective oil and gas recovery.
- Europe (0.93)
- Asia > Russia > Siberian Federal District > Irkutsk Oblast > Kataganskiy District (0.15)
- Europe > United Kingdom > North Sea > Southern North Sea > Southern Gas Basin > Sole Pit Basin > Block 49/21 > V-Fields > Vulcan Formation (0.99)
- Europe > United Kingdom > North Sea > Southern North Sea > Southern Gas Basin > Sole Pit Basin > Block 49/16 > V-Fields > Vulcan Formation (0.99)
- Europe > United Kingdom > North Sea > Southern North Sea > Southern Gas Basin > Sole Pit Basin > Block 48/25b > V-Fields > Vulcan Formation (0.99)
- (2 more...)
- Well Drilling > Drilling Operations > Directional drilling (1.00)
- Reservoir Description and Dynamics > Unconventional and Complex Reservoirs > Gas-condensate reservoirs (1.00)
- Reservoir Description and Dynamics > Reservoir Simulation (1.00)
- (7 more...)
- Information Technology > Modeling & Simulation (0.68)
- Information Technology > Data Science (0.46)
Abstract Horizontal wells with multistage hydraulic fracturing stimulation become the common practice in developing tight and shale gas reservoirs. For gas condensate reservoirs, heavier components in the gas phase start dropping and decrease the gas mobility due to a relative-permeability relationship as reservoir pressure drops below the saturation pressure. Therefore, modeling the condensate banking along hydraulic fractures becomes critical in understanding the productivity loss, the hydraulic fracturing job design as well as the field production optimization. In addition, along with pressure depletion, the stress dependent permeability must be taken into account either by an approximation derived from lab experiments inside a finite difference flow simulator or modeling separately by a finite element geomechanics code. A condensate fluid pseudoization that reduces nine hydrocarbon components to a pseudo three components mixture is presented in this paper. The control volume based multiphase multi-components thermal simulator FATS is utilized in modeling the condensate banking inside the hydraulic fractures and surrounding matrix blocks. A K-value interpolation algorithm is developed and validated by a two-phase envelope generated by an Equation of State (EOS). FATS results are validated by the EOS based reservoir simulator GEM. A compositional simulation model is coupled with reservoir geomechanics in this study to investigate the interaction of stress changes and its effects on multiphase flow along fractures. A modular coupled approach is implemented for solving the stress and flow equations at each time step by the iteration between the reservoir simulator and geomechanical module. Pressure and temperature changes occurring in the reservoir simulator are passed to the geomechanical simulator to compute the changing of stress and strain and updating porosity and permeability simultaneously. Simulation results show that fracture conductivity reduction is due to the combination of condensate banking and changing of the effective stress along hydraulic fractures.
- Europe > Norway > Norwegian Sea > Halten Terrace > PL 479 > Block 6506/12 > Åsgard Field > Smørbukk Field > Åre Formation (0.99)
- Europe > Norway > Norwegian Sea > Halten Terrace > PL 479 > Block 6506/12 > Åsgard Field > Smørbukk Field > Tofte Formation (0.99)
- Europe > Norway > Norwegian Sea > Halten Terrace > PL 479 > Block 6506/12 > Åsgard Field > Smørbukk Field > Tilje Formation (0.99)
- (4 more...)
- Well Completion > Hydraulic Fracturing (1.00)
- Reservoir Description and Dynamics > Unconventional and Complex Reservoirs > Gas-condensate reservoirs (1.00)
- Reservoir Description and Dynamics > Reservoir Simulation (1.00)
- (4 more...)
Abstract In low and tight gas formations, condensate banking will form in shortly time after production start-up due to pressure drop below the saturation pressure. Mobility reduction near wellbore area will affect well productivity. The prediction of gas condensate wells production will strongly depend on oil banking evaluation and modeling. A benchmark radial fine well model has been built using constant petrophysical properties per each layer. Several coarse Cartesian grids have been considered to evaluate discrepancies in terms of production and flowing pressure with respect to the benchmark grid. For a coarser Cartesian grid, it has been deduced that Generalized Pseudo-Pressure (GPP) is a key parameter to avoid well performance over-estimation. An alternative solution consists in defining a local grid refinement (LGR) near wellbore to honour the benchmark solution without using GPP. In this case study a LGR technique has been used to incorporate future hydraulic fractures for the wells development. A real application case has been considered to extend lessons learned from benchmark to field scale. A proper geological model has been built using a sedimentological model as driver for petrophysical properties distribution. Two DST have been considered to analyze condensate banking phenomena evaluation in a low and medium permeability matrix. To this purpose, three analytical models have been considered. Thus, to validate a representative analytical model a numeric simulation has been performed. Based on the obtained results, it can be affirmed that the radial composite is the most appropriate analytical model reproducing the phenomenon of gas mobility reduction in the nearest wellbore region.
- Geology > Sedimentary Geology (0.67)
- Geology > Rock Type > Sedimentary Rock > Clastic Rock (0.47)
- Well Completion > Hydraulic Fracturing (1.00)
- Reservoir Description and Dynamics > Unconventional and Complex Reservoirs > Gas-condensate reservoirs (1.00)
- Reservoir Description and Dynamics > Reservoir Simulation (1.00)
- (5 more...)