The SPE has split the former "Management & Information" technical discipline into two new technical discplines:
- Data Science & Engineering Analytics
The SPE has split the former "Management & Information" technical discipline into two new technical discplines:
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Bigdeli, Alireza (Universidade Estadual De Campinas) | von Hohendorff Filho, João Carlos (Universidade Estadual De Campinas) | Schiozer, Denis José (Universidade Estadual De Campinas)
Abstract In this work, we present a case study of the integration of surface facility models and a deepwater reservoir, as well as an engineering evaluation of the implications of liquid-liquid subsea separation (LLSS) on the integration process. For this, a heavy oil sandstone reservoir and several surface facility layouts were computationally integrated using a commercial simulator. A gathering unit, subsea separator, and water disposal unit were added to the surface facility model layouts to support the LLSS system. The term "merge scenario" was used to refer to the quantity of production streams that were gathered and delivered to the subsea separator. To allow the production from the reservoir model, the minimum bottom-hole pressure (BHP) for the producing wells were defined for all the simulations. Our investigation includes fluids produced at platforms, produced water at disposal unit, the pressure drop in the riser in terms of hydrostatic and friction terms, and economic analyses of these investigations. This case study shows that, depending on the merging situation, the reservoir needs 2 to 5 times more injection water than the separated water. Despite efforts to reduce the pressure restriction in the surface facility by increasing the riser diameter, the oil recovery did not change significantly when the number of merging wells was adjusted. This happened because the wellhead was not affected by the production system's pressure disturbance and the surface facility models’ boundary conditions remained unchanged. The economic calculations also indicated that the value of the technology (the highest acceptable price for the technology) for eleven merge scenario was 130 MMUSD and the OPEX and CAPEX can be lowered by 95 and 35 MMUSD (3% and 5% on average), respectively. This economic benefit was due to the lower cost of platform water handling from the produced water separation. In later stages of simulations, when the water cut surpasses 90%, hydrostatic pressure loss overtakes friction pressure loss as the primary contributor to overall pressure losses in the riser for 11 merge scenarios. These tests demonstrated that adding LLSS increases the complexity of the integration process and engineers can apply the engineering ideas of this study to other field designs in development. This work is the first case study of its kind that examines the relationship between the impact of LLS and the integration of a deep-water reservoir and surface facility model. This article's production forecast problem description can be utilized as a starting point to develop a general methodology for simulating complicated offshore production systems using LLSS operations.
Abstract Due to the maturity of water-flooded oil reservoirs, as a consequence of heterogeneity, fluids move preferentially through the most permeable layers, leaving large volumes of mobile oil remain unswept. Injection of oil-in-water (O/W) dispersions can regulate the permeability contrast between these layers. Droplet size distribution and porous media heterogeneity are the principal features that characterize displacement front uniformity. The intent of this work is therefore to provide a fundamental insight into number of factors may influence the dispersion flow in porous media. The workflow in this study is comprised of three stages. First, O/W dispersions with low oil concentrations were prepared and characterized. Second, a series of O/W dispersion injection experiments was conducted. The objective of this stage was to evaluate the distribution of retained oil droplets, pressure drop and permeability reduction in different sandstone core-plugs. Finally, a mathematical model based on the experimental setup was developed to describe the dynamics of O/W dispersion flow. Finite element method (FEM) was employed to numerically solve the governing equations. The experimental results revealed that the number and size of retained oil droplets decay with the core depth and correspondingly in the effluent. Verification of the numerical model was performed by comparing the pressure drop and permeability reduction to the results of analytical solutions. The model showed good validation with the experimental data. The numerical results were closely match those of the analytical solutions. The current work presents a potentially efficient method of modelling to describe the dispersion flow in porous media. However, for field applications, further improvement to the model complexity is required.
Shaker Shiran, Behruz (NORCE Norwegian Research Centre AS) | Djurhuus, Ketil (NORCE Norwegian Research Centre AS) | Alagic, Edin (NORCE Norwegian Research Centre AS) | Lohne, Arild (NORCE Norwegian Research Centre AS) | Rolfsvåg, Trond Arne (Hydrophilic AS) | Syse, Harald (Hydrotell AS) | Riisøen, Solveig (Hydrotell AS)
Abstract As oil is produced from a reservoir, the free-water-level (FWL) rises. Monitoring the FWL during oil production is of high value for the operators. This knowledge can aid placement of new wells on the field, improve the production strategy on a well level and reduce the production of water. We propose a new method for continuously measuring in-situ water pressure in an oil reservoir and investigate, both experimentally and by simulations, how this information can be used in reservoir monitoring. Laboratory experiments with Berea sandstone and Mons chalk core samples were performed using mineral oil and synthetic brine in a test setup designed for this study. The pressure in the water phase is measured with hydrophilic probes at five locations on the core during drainage and imbibition processes. Data including temperatures, pressures, resistance, water production, and pump logs were continuously collected in a cloud solution for live monitoring during the experiments. The experimental results were interpreted using a numerical simulator (IORCoreSim) to identify key mechanisms behind probe response and upscaling to reservoir scale. A new setup with 5 internal pressure probes for measuring in-situ water pressure with higher oil pressure was successfully designed and tested. An advanced watering system to inject water to the probe tips was included in the test setup and can be operated automatically. Experimental results showed that the water-wet probes can measure low water pressure inside high pressure oil column. The change in water pressure during drainage of low permeable Mons core and medium permeability Berea core was continuously measured. The probes were able to measure water pressure in different sections of the core with change of water saturation in the core. After the drainage process, the water pressure at one side of the core was increased. The propagation of water pressure at low water saturations were then detected in the 5 probes along the core sample. This paper presents a revolutionary technique to measure pressure in a thin film of water with low mobility. Continuous monitoring of water pressure inside the hydrocarbon phase can be used to enhance the production on a well level and improve the strategy on a field level. This results in increased production, reduced operational costs and environmental impacts.
Abstract Injecting fluid into subsurface strata has the potential to cause earthquakes by altering pore pressure and subsurface stress. To assess the seismic hazard associated with subsurface flow processes, it is necessary to understand the underlying mechanics of fluid-induced fault reactivation. In this study, we conduct a coupled hydro-mechanical modeling of fluid injection to a strike-slip fault with rate-and-state friction. We account for the fluid flow across and along the fault, as well as the hydromechanical properties of faults in the normal and tangential directions. We model the injection-induced slip of a strike-slip fault, and the simulation results indicate that there are two primary factors that affect injection-induced seismicity. The first factor is that the initiation of rupture is directly related to the diffusion of pore pressure in the near field where there is high shear stress and a large reduction in fault strength due to the significant pressure change. The second factor is that the transfer of shear stress from the nucleation zone promotes the advancement of the slip front to the near- and far field. Our results are quite conservative since the model chose pf as the relevant pressure when calculating the effective normal stress and the shear stress has a slight effect on the pressure variation. Finally, the sensitivity analysis indicates that greater tangential permeability values delay the onset of fault rupture and diminish the likelihood of fault reactivation. Higher stiffness induces fault slip earlier but reduces its magnitude.
Abstract Reservoir simulators based on physics provide the most accurate method for predicting oil and gas recovery, in particular from waterflood and EOR processes. However, detailed full-field simulation can be computationally demanding. In recent years, there have been attempts in accelerating reservoir simulation by combining simplification of the gridding requirement with data-driven approaches while maintaining the full physics. One such approach is the physics-based data-driven flow network model where 1D or 2D grids connecting the wells are configured and simulated. The parameters of the flow network model are then tuned to match full 3D simulation or field-data. Even though the grid has been simplified, a large number of parameters are needed to reproduce the 3D simulation results. In this paper, an approach similar to the flow network model is presented. The main contribution of this paper is the parameterization of the gridding process between the wells such that a minimal number of parameters are needed. Essentially, the grids between the wells are configured to model accurately the flow behavior. The corner-point grid geometry is kept so that current simulators could be used with the proposed method. In this paper, the grid geometry is determined with AI methods for one waterflood run. The grid could be used subsequently for waterflood with widely different injection/production scenarios and even for chemical flood. The ability of the approach to derive the grid from a single waterflood run is another significant contribution of this paper.
Abdelkareem, Sherif Shaban (TU Clausthal / Equinor) | Grimstad, Alv-Arne (SINTEF) | Bergmo, Per Eirik (SINTEF) | Gaol, Calvin Lumban (TU Clausthal) | Jahanbani Ghahfarokhi, Ashkan (NTNU) | Lothe, Ane Elisabet (SINTEF) | Ringstad, Cathrine (SINTEF) | Ganzer, Leonhard (TU Clausthal)
Abstract The latest report of the UN International Panel on Climate Change (IPCC) has affirmed once again the urgent need for carbon capture and storage (CCS) to realize the international climate ambitions. Deployment of CCS technologies is a fundamental key to reach the 1.5°C climate target since the estimated global technical geological CO2 storage capacity is 1000 gigatons, which is higher than the CO2 storage needs through 2100. In this study, the dynamic carbon dioxide storage capacity for a potential CO2 storage site in the Trøndelag platform is investigated. The Garn formation of the selected site in the Norwegian Sea has promising geological characteristics and is here considered to be the main storage formation. A conceptual geological model has been built based on the available geological data which have been mainly extracted from the literature. Three main realization models representing different porosity and permeability ranges are constructed. Dynamic reservoir simulation studies for each realization are run with an injection rate of 2 million tonnes per year for 50 years and continued for 70 years of post-injection. Sensitivity analyses investigate different parameters’ effect on the CO2 plume, pressure development, and CO2 storage capacity. The sensitivity parameters include relative permeability, injection rate, number of injection wells, perforation length, boundary conditions, fault transmissibility and capillary pressure effects. The results after 120 and 240 years of total simulation time, show the clear effect of saturation functions on plume migration and CO2 dissolution into the water phase. The porosity and permeability variations within a specific range have a minor effect on the pressure development and dissolved/trapped CO2 amounts but mostly affects the CO2 plume shape, extent, and migration speed. Doubling the injection rate using one well will increase the dissolved and trapped CO2 amounts by more than 70% and 90% by the end of simulation, respectively. While injecting the doubled CO2 amount using two wells will lead, up to 130 % and 115 % rise in the dissolved and trapped CO2 amounts, respectively. For both cases with the double injected amount, the increase in the average field pressure during injection is about twice the increase in the base case. A sharp rise in the average field and near-wellbore pressures has been noticed when the boundary conditions are closed demonstrating the importance of hydraulic communication with the wider connected pore volume, represented through analytical Carter-Tracy aquifers in the base case scenarios to represent the semi-open full volume of the Garn Formation. Without the external pore volume, a sharp increase in formation pressure led to an automatic shutdown of the injection well which caused a reduction in the injected CO2 amount. Increasing the perforation length of the injection well, eliminating fault transmissibility as well as including a non-zero capillary pressure showed no significant effect on CO2 plume, and pressure development after 120 years of simulation, while a slight change in the dissolved and trapped CO2 amounts is observed. The effect of these sensitivity parameters may be obvious if the simulation time is increased. This study mainly confirms that this structure in the Trøndelag Platform can store up to 200 Mt of CO2 as predicted in previous work. This makes the selected structure a potential CO2 storage site in the Norwegian Sea for future CCS projects.
Gudala, Manojkumar (King Abdullah University of Science and Technology) | Xu, Zhen (King Abdullah University of Science and Technology) | Tariq, Zeeshan (King Abdullah University of Science and Technology) | Yan, Bicheng (King Abdullah University of Science and Technology) | Sun, Shuyu (King Abdullah University of Science and Technology)
Abstract In this study we developed mathematical model for thermo-hydro-mechanical process occurs within the geothermal reservoir with variable rock/fracture/fluid parameters. The influence of fracture network on the cold plume movement, pore pressure, changes in the rock/fracture effective stress under the same operating conditions. The injected fluid transport to extraction well from injection well within the interconnected fractures. In the same direction variation of the effective stress, pore pressure both in rock matrix and fractures was observed. Due to the variation of effective stress in the fracture, it will undergo shearing and alter the fracture aperture. This variation of fracture aperture will create a micro-seismic moment in the fractured geothermal reservoir. The magnitude of micro-seismic moment and hyper center were changing with time and highly sensitive to the fracture connectivity of each fracture set. The developed mathematical model was observed these variations efficiently. Thus, the developed model can be utilized to address the variations occurred throughout the heat extraction in the fractured geothermal reservoir in conjunction with the activation of fracture and location of hyper center of each seismic moment.
Dong, Xiaohu (China University of Petroleum-Beijing) | Zhang, Hao (China University of Petroleum-Beijing) | Lu, Ning (China University of Petroleum-Beijing) | Xiao, Zhan (China University of Petroleum-Beijing) | Lyu, Xiaocong (China University of Petroleum-Beijing) | Liu, Huiqing (China University of Petroleum-Beijing) | Chen, Zhangxin (University of Calgary)
Abstract Steam injection process is usually the primary extraction method for heavy oil reservoirs. But, in recent decades, with the steam injection operation continues, most of the steamed heavy oil reservoirs have achieved a depleted status (residual oil zone). Meanwhile, for most post steamed heavy oil reservoirs, the average formation temperature can reach above 150℃. It indicates that they can be considered as a potential artificial geothermal energy source. In this work, those post steamed heavy oil reservoirs are proposed as a source of artificial geothermal energy, and the extraction potential is evaluated. A heavy oil reservoir simulation model is firstly constructed based on a geological model which involves a five-spot well pattern of steam flooding operation in Shengli oilfield, Sinopec. This model can be used to represent a depleted status of a steamed heavy oil reservoir. Subsequently, based on this five-spot well pattern of steam flooding, a geothermal heat extraction model is developed. In order to accurately evaluate the extraction potential of this artificial geothermal energy, the wellbore heat loss is also considered by using a discretized wellbore model. Thus, two different extraction methods of water injection and CO2 injection are simulated. Then, based on the simulation model, the factors that control the heat extraction rate in high temperature depleted heavy oil reservoirs are also discussed. Results show that a post steamed heavy oil reservoir can be a potential source of geothermal energy. By using the existing steam flooding well pattern, the initial investment is reduced, thus, a high-efficient development can be achieved. From the simulation results, it is found that the method of geothermal energy extraction in high temperature depleted heavy oil reservoir (165 ℃, 2 MPa) using CO2 can achieve a high-speed geothermal energy extraction process in the early stage (<1.5 years). In comparison, a method of water injection process performs better within a longer time period (>1.5 years). Simultaneously, it is found that the bottom-hole pressure, heat extraction time and CO2 injection rate can have the biggest impact on the heat extraction rate. Because of the high temperature condition, the post steamed heavy oil reservoirs can have a huge potential of heat mining. The technology of geothermal energy extraction can further enhance their development value and prolong the working life.
Perez-Perez, Alfredo (CHLOE, University of Pau) | Romero, Carolina (TotalEnergies S.A.) | Santanach-Carreras, Enric (TotalEnergies S.A.) | Skauge, Arne (Energy Research Norway)
Abstract The injection of alkali in acidic viscous oils is known to promote the in-situ formation of emulsions during chemical oil recovery. Naphthenic acid components react with the alkali to form in-situ surfactants, which support oil emulsification at the water-oil interface. It is believed that emulsification and transport of the dispersed oil in the presence of polymer can significantly improve oil recovery. In earlier work, we proposed a new mechanistic non-equilibrium model to simulate alkali-polymer processes for different oil viscosities (2000 – 3500 cP at 50°C) with an acid number of around 4 mg KOH/g. The model considers emulsion generation kinetics, polymer, and emulsion non-Newtonian viscosity through a straightforward modelling strategy. The emulsified oil was treated as a dispersed component in water phase (O/W emulsion), while the water phase mobility considered the apparent aqueous phase viscosity containing dispersed oil and polymer. In the above referenced work, seven alkali-polymer corefloods performed with different alkali types and slug sizes were history matched. We showed that the model is capable of appropriately matching the experiments. Kinetics obtained by history match show that emulsion formation under the conditions here studied is alkali type dependent. In the current work, we applied our alkali-polymer model in two displacement tests (Hele Shaw cell) with two different oil viscosities (2000 – 200 cP at 50°C). These new experiments included secondary water flood, tertiary polymer flood and quaternary alkali-polymer flood. The initial conditions of alkali-polymer (AP) flood were obtained after properly modelling the unstable immiscible floods and polymer floods. For modelling the polymer floods (2D slabs), three models were evaluated: 1) extension of relative permeability curves applied to water flood, 2) Killough method (hysteresis for the water phase) and relative permeability power-law extensions and 3) two relative permeability curves with polymer concentration dependency. Our alkali-polymer model was employed for simultaneously history matching 1D and 2D experiments performed with 5 g/L of Na2CO3 and polymer. When comparing alkali-polymer results, a good agreement was found for the complete set of experiments. In addition, fitting parameters (kinetics and emulsion viscosity) were close to the parameters reported in the earlier study. Finally, fitted alkali-polymer parameters were employed for predicting alkali-polymer outputs in the second slab (with similar alkali-polymer concentration but lower oil viscosity). Even if experimental observations are relatively well represented, a lower value of incremental oil recovery (<3 % OOIP) was obtained. We believe that the use of a less viscous oil (diluted oil) in the experiments may influence the generation and transport of formed emulsions.
Abstract In this paper, we propose a Control Volume Material Balance (CVMB) approach for proxy reservoir simulation and apply it to real-time flow diagnostics. Instead of utilizing a comprehensive reservoir simulator, it estimates the saturations distributions by mapping the mass difference between injected and produced fluids recorded at wells into 3D grid blocks. On this basis, we perform real-time flow diagnostics to evaluate the dynamic heterogeneity of the instantaneous displacement flow field which can be used for making effective and opportune decisions to improve oil recovery. CVMB solves the pressure and flow fields implicitly, and the transport equations explicitly. It incorporates 3D heterogenous rock properties. The fundamental idea of the CVMB method is to divide the 3D flow field into a series of 1D well-pair Control Volumes (CVs). A well-pair Control Volume is composed of grid blocks in the intersection of the sweep and drainage regions of the injector and producer. The fluid flow in and out of the 1D CV can only occur at the wells, and the in-situ fluid volumes are determined by the well flow rates and the well allocation factors. In each CV, we assume the displacement in the grid blocks is piston-like and follows the 1D order of ascending forward time-of-flight. The fluid saturation distributions are determined by defining the cut-off time-of-flight for the displacement front. We show how the CVMB method improves the pattern-based mass balance approaches in the following aspects: 1) enables real-time flow diagnostics in terms of the hydrocarbon dynamic Lorenz coefficient without a comprehensive reservoir simulator; 2) enhances the simplicity and extensibility of the pattern-based mass balance approach without mapping between grid blocks and streamlines; 3) reduces the smearing effects in conventional mass balance approach by defining 1D CVs using forward time-of-flight. The proposed CVMB method utilizes the historical well flow rates as the input to estimate the swept regions and its average saturation with remarkable efficiency and sufficient accuracy for real-time flow diagnostics.