We present a CT coreflood study of foam flow with two representative oils: hexadecane C16 (benign to foam) and a mixture of 80 wt% C16 and 20 wt% oleic acid (OA) (very harmful to foam). The purpose is to understand the transient dynamics of foam, both generated in-situ and pre-generated, as a function of oil saturation and type. Foam dynamics with oil (generation and propagation) are quantified through sectional pressure-drop measurements. Dual-energy CT imaging monitors phase saturation distributions during the corefloods. With C16, injection with and without pre-generation of foam exhibits similar transient behavior: strong foam moves quickly from upstream to downstream and creates an oil bank. In contrast, with 20 wt% OA, pre-generation of foam gives very different results from co-injection, suggesting that harmful oils affect foam generation and propagation differently. Without pre-generation, initial strong-foam generation is very difficult even at residual oil saturation about 0.1; the generation finally starts from the outlet (a likely result of the capillary-end effect). This strong-foam state propagates backwards against flow and very slowly. The cause of backward propagation is unclear yet. However, pre-generated foam shows two stages of propagation, both from the inlet to outlet. First, weak foam displaces most of the oil, followed by a propagation of stronger foam at lower oil saturation. Implicit-texture foam models for enhanced oil recovery cannot distinguish the different results between the two types of foam injection with very harmful oils. This is because these models do not distinguish between pre-generation and co-injection of gas and surfactant solution.
Schmidt, Julia (Delft University of Technology) | Mirzaie Yegane, Mohsen (Delft University of Technology) | Dugonjic-Bilic, Fatima (TouGas Oilfield Solutions) | Gerlach, Benjamin (TouGas Oilfield Solutions) | Zitha, Pacelli (Delft University of Technology)
Synthetic high molecular weight polymers have been utilized for enhanced oil recovery applications. Improving their injectivity remains an important issue for field applications. Large entangled polymer chains can clog pore throats, leading to injectivity decline. We investigated an emulsion polymer system and have developed a series of processing techniques to condition an acrylamide-based copolymer inverse emulsion system at a salinity of 50,000 ppm
The un-conditioned polymer system and test conditions were chosen to clearly demonstrate the impact of processing techniques on the injectivity behavior. The polymer solution was sheared with two agitators, a disperser and Ultra-Turrax, at different intensities and with a pressure-driven flow into a thin capillary to reduce the size of the largest polymer chains and disentangle the polymer chains while maintaining its viscosifying power. The injectivity of such differently sheared solutions was evaluated by performing filtration tests using a 1-micron membrane and sand-pack flooding tests.
Our experiments have established a master curve showing viscosity and screen factor dependences on accumulated energy during pre-shearing, regardless of the mode of shearing. The un-sheared polymer solution had an unfavorable behavior in filtration test and sand-pack flooding experiment. After pre-shearing, the filtration behavior of polymer solution and the injectivity in sand-packs improved significantly. Polymer solutions sheared with a disperser at an energy input of 15 MJ/m3 improved the injectivity gradient (e.g. the ratio of the resistance factor over 30 pore volumes injected) from 3.7 to 1.6, while the viscosifying power was reduced by only 2%. To reach the same injectivity improvement with Ultra-Turrax, an energy input of 31 MJ/m3 were required, which reduced the viscosity by 11%. Shearing the solution using a capillary at an energy input of 50 MJ/m3, did not reduce the injectivity gradient while viscosity was reduced by 19%. This indicates that the injectivity performance is shear-origin dependent and the resulting polymer structure, when sheared through contractions, has a different alignment as compared to shearing with the agitators, the disperser and Ultra-Turrax.
Foam-Assisted Surfactant Flooding (FASF) is a novel enhanced oil recovery (EOR) method combining the reduction of oil-water (o/w) interfacial tension (IFT) to ultra-low values and foaming of a gas drive for mobility control. We present a detailed laboratory study on the FASF process at reservoir conditions. The stability of two specially selected surfactants in the vicinity of original injection water, i.e. sea water, at 90°C was assessed. The phase behaviour of the crude oil-surfactant-brine systems and the ability of the two selected surfactants to generate stable foam in bulk were studied in presence and in absence of crude oil. The phase behaviour and bulk tests resulted in the formulations of the surfactant slug and drive solutions. The slug solution aims for oil mobilisation by lowering of the o/w IFT and the drive formulation is required for gas foaming for mobility control. CT scanned core-flood experiments were conducted in Bentheimer sandstone cores initially brought to residual oil by water flooding. Oil mobilisation was obtained by injecting a surfactant slug at either under-optimum (o/w IFT of 10-2 mN/m) or optimum (o/w IFT of 10-3 mN/m) salinity conditions. At both salinities the injected surfactant slug yielded the formation of an unstable oil bank due to dominant gravitational forces. Optimum salinity surfactant slug was notably more effective at reducing residual oil to waterflood (81% reduction) compared to the under-optimum salinity slug (30% reduction). After oil mobilisation, drive foam was either generated in-situ by co-injection with nitrogen gas or was pre-generated ex-situ and then injected to displace mobilised oil. It was found that, at optimum salinity, FASF yielded an ultimate recovery factor of 40±5% of the oil in place (
HosseiniMehr, Mousa (Delft University of Technology) | Arbarim, Rhadityo (Delft University of Technology) | Cusini, Matteo (Delft University of Technology) | Vuik, Cornelis (Delft University of Technology) | Hajibeygi, Hadi (Delft University of Technology)
A dynamic multilevel method for fully-coupled simulation of flow and heat transfer in heterogeneous and fractured geothermal reservoirs is presented (FG-ADM). The FG-ADM develops an advanced simulation method which maintains its efficiency when scaled up to field-scale applications, at the same time, it remains accurate in presence of complex fluid physics and heterogeneous rock properties. The embedded discrete fracture model is employed to accurately represent fractures without the necessity of unstructured complex grids. On the fine-scale system, FG-ADM introduces a multi-resolution nested dynamic grid, based on the dynamic time-dependent solution of the heat and mass transport equations. The fully-coupled implicit simulation strategy, in addition to the multilevel multiscale framework, makes FG-ADM to be stable and efficient in presence of strong flow-heat coupling terms. Furthermore, its finite-volume formulation preserves local conservation for both mass and heat fluxes. Multi-level local basis functions for pressure and temperature are introduced, in order to accurately represent the heterogeneous fractured rocks. These basis functions are constructed at the beginning of the simulation, and are reused during the entire dynamic time-dependent simulation. For several heterogeneous test cases with complex fracture networks we show that, by employing only a fraction of the fine-scale grid cells, FG-ADM can accurately represent the complex flow-heat solutions in the fractured subsurface formations.
Sun, Yimin (Aramco Research Center – Delft, Aramco Overseas Company B.V.) | Kim, YoungSeo (EXPEC ARC, Saudi Arabian Oil Company) | Qu, Shan (Delft University of Technology) | Verschuur, Eric (Delft University of Technology)
Joint migration inversion (JMI) is a recently developed technology that aims at incorporating the seismic velocity model update and acoustic migration, including all multiple scatterings, into one closed-loop process. Full waveform inversion (FWI) is a commonly accepted technology for velocity model building, and reverse-time migration (RTM) is the main method adopted for depth imaging. In this paper we first use a 2D realistic deep water model to benchmark JMI against a workflow of FWI combined with RTM. With some insights on JMI gained from this comparison study, we point out that a good niche for JMI is to provide a high quality initial velocity model. We further demonstrate the performance of JMI on a 2D deep water field dataset with an initial velocity model derived from migration velocity analysis (MVA).
Foam reduces gas mobility and can improve sweep efficiency in an enhanced-oil-recovery (EOR) process. Previous studies show that foam can be generated in porous media by exceeding a critical velocity or pressure gradient. This requirement is typically met only near the wellbore, and it is uncertain whether foam can propagate several tens of meters away from wells as the local pressure gradient and superficial velocity decreases. Theoretical studies show that foam can be generated, independent of pressure gradient, during flow across an abrupt increase in permeability. In this study, we validate theoretical predictions through a variety of experimental evidence. Coreflood experiments involving simultaneous injection of gas and surfactant solution at field-like velocities are presented. We use model consolidated porous media made out of sintered glass, with a well-characterized permeability transition in each core. The change in permeability in these artificial cores is analogous to sharp, small-scale heterogeneities, such as laminations and cross laminations. Pressure gradient is measured across several sections of the core to identify foam-generation events and the subsequent propagation of foam. X-ray computed tomography (CT) provides dynamic images of the coreflood with an indication of foam presence through phase saturations. We investigate the effects of the magnitude of permeability contrast on foam generation and mobilization. Experiments demonstrate foam generation during simultaneous flow of gas and surfactant solution across a sharp increase in permeability, at field-like velocities. The experimental observations also validate theoretical predictions of the permeability contrast required for foam generation by “snap-off” to occur at a certain gas fractional flow. Pressure-gradient measurements across different sections of the core indicate the presence or absence of foam and the onset of foam generation at the permeability change. There is no foam present in the system before generation at the boundary. CT measurements help visualize foam generation and propagation in terms of a region of high gas saturation developing at the permeability transition and moving downstream. If coarse foam is formed upstream, then it is transformed into stronger foam at the transition. Significant fluctuations are observed in the pressure gradient across the permeability transition, suggesting intermittent plugging and mobilization of flow there. This is the first CT-assisted experimental study of foam generation by snap-off only, at a sharp permeability increase in a consolidated medium. The results of experiments reported in this paper have important consequences for a foam application in highly heterogeneous or layered formations. Not including the effect of heterogeneities on gas mobility reduction in the presence of surfactant could underestimate the efficiency of the displacement process.
Tang, Jinyu (Delft University of Technology) | Vincent-Bonnieu, Sebastien (Delft University of Technology and Shell Global Solutions International) | Rossen, William (Delft University of Technology)
Foam flow in porous media without oil shows two regimes depending on foam quality (gas fractional flow). Complexity and limited data on foam/oil interactions in porous media greatly restrict understanding of foam in contact with oil. Distinguishing which regimes are affected by oil is key to modeling the effect of oil on foam. We report steady-state corefloods to investigate the effect of oil on foam through its effect on the two flow regimes. We fit the parameters of a widely used local-equilibrium (LE) foam model to data for concurrent foam/oil flow. This research provides a practical approach and initial data for simulating foam enhanced oil recovery (EOR) in the presence of oil.
To ensure steady state, oil is coinjected with foam at a fixed ratio of oil (Uo) to water (Uw) superficial velocities in a Bentheimer Sandstone core. Model oils used here consist of a composition of hexadecane, which is benign to foam stability, and oleic acid (OA), which can destroy foam. Varying the concentration of OA in the model oil allows one to examine the effect of oil composition on steady-state foam flow. Experimental results show that oil affects both high- and low-quality regimes, with the high-quality regime being more sensitive to oil. In particular, oil increases the limiting water saturation (S*w) in the high-quality regime and also reduces gas-mobility reduction in the low-quality regime. Unevenly spaced pressure-gradient contours in the high-quality regime suggest either strongly shear-thinning behavior or an increasingly destabilizing effect of oil. In some cases, the pressure gradient in the low-quality regime decreases with increasing Uw at fixed gas superficial velocity (Ug), either with or without oil. This might reflect either an effect of oil, if oil is present, or easier flow of bubbles under wetter conditions. Increasing the OA concentration extends the high-quality regime to lower foam qualities, indicating more difficulty in stabilizing foam. Thus, oil composition plays as significant a role as oil saturation (So).
A model fit assuming a fixed S*w and including shear thinning in the low-quality regime does not represent the two regimes when the oil effect is strong enough. In such cases, fitting S*w to each pressure-gradient contour and excluding shear thinning in the low-quality regime yield a better match to these data. The dependency of S*w on So is not yet clear because of the absence of oil-saturation data in this study. Furthermore, none of the current foam-simulation models captures the upward-tilting pressure-gradient contours in the low-quality regime.
An enhanced-oil-recovery (EOR) pilot test has multiple goals, among them to be profitable (if possible), demonstrate oil recovery, verify the properties of the EOR agent in situ, and provide the information needed for scaleup to an economical process. Given the complexity of EOR processes and the inherent uncertainty in the reservoir description, it is a challenge to discern the properties of the EOR agent in situ in the midst of geological uncertainty. We propose a numerical case study to illustrate this challenge: a polymer EOR process designed for a 3D fluvial-deposit water/oil reservoir. The polymer is designed to have a viscosity of 20 cp in situ. We start with 100 realizations of the 3D reservoir to reflect the range of possible geological structures honoring the statistics of the initial geological uncertainties. For a population of reservoirs representing reduced geological uncertainty after 5 years of waterflooding, we select three groups of 10 realizations out of the initial 100, with similar water-breakthrough dates at the four production wells. We then simulate 5 years of polymer injection. We allow that the polymer process might fail in situ and viscosity could be 30% of that intended. We test whether the signals of this difference at injection and production wells would be statistically significant in the midst of geological uncertainty. Specifically, we compare the deviation caused by loss of polymer viscosity with the scatter caused by the geological uncertainty using a 95% confidence interval. Among the signals considered, polymer-breakthrough time, minimum oil cut, and rate of rise in injection pressure with polymer injection provide the most-reliable indications of whether a polymer viscosity was maintained in situ.
Gong, Jiakun (Delft University of Technology) | Vincent-Bonnieu, Sebastien (Shell Global Solutions International B.V.) | Kamarul Bahrim, Ridhwan Zhafri (Petronas) | Che Mamat, Che Abdul Nasser Bakri (Petronas) | Tewari, Raj Deo (Petronas) | Groenenboom, Jeroen (Shell Global Solutions International B.V.) | Farajzadeh, Rouhollah (Delft University of Technology and Shell Global Solutions International B.V.) | Rossen, William R. (Delft University of Technology)
Surfactant alternating gas (SAG) is often the injection strategy used for injecting foam into a reservoir. However, liquid injectivity can be very poor in SAG, and fracturing of the well can occur. Coreflood studies of liquid injectivity directly following foam injection have been reported. We conducted a series of coreflood experiments to study liquid injectivity under conditions more like those near an injection well in a SAG process in the field (i.e., after a period of gas injection). Our previous experimental results suggest that the injectivity in a SAG process is determined by propagation of several banks. However, there is no consistent approach to modeling liquid injectivity in a SAG process. The Peaceman equation is used in most conventional foam simulators for estimating the wellbore pressure and injectivity.
In this paper, we propose a modeling approach for gas and liquid injectivity in a SAG process on the basis of our experimental findings. The model represents the propagation of various banks during gas and liquid injection. We first compare the model predictions for linear flow with the coreflood results and obtain good agreement. We then propose a radial-flow model for scaling up the core-scale behavior to the field. The comparison between the results of the radial-propagation model and the Peaceman equation shows that a conventional simulator based on the Peaceman equation greatly underestimates both gas and liquid injectivities in a SAG process. The conventional simulator cannot represent the effect of gas injection on the subsequent liquid injectivity, especially the propagation of a relatively small region of collapsed foam near an injection well. The conventional simulator’s results can be brought closer to the radial-flow-model predictions by applying a constant negative skin factor.
The work flow described in this study can be applied to future field applications. The model we propose is based on a number of simplifying assumptions. In addition, the model would need to be fitted to coreflood data for the particular surfactant formulation, porous medium, and field conditions of a particular application. The adjustment of the simulator to better fit the radial-flow model also would depend, in part, on the grid resolution of the near-well region in the simulation.
The effectiveness of foam for mobility control in the presence of oil is key to foam enhanced oil recovery (EOR). A fundamental property of foam EOR is the existence of two steady-state flow regimes: the high-quality regime and the low-quality regime. Experimental studies have sought to understand the effect of oil on foam through its effect on these two regimes. Here, we explore the effect of oil on the two flow regimes for one widely used foam model.
The STARS (CMG 2015) foam model includes two algorithms for the effect of oil on foam: In the "wet-foam" model, oil changes the mobility of full-strength foam in the low-quality regime, and in the "dry-out" model, oil alters the limiting water saturation around which foam collapses. We examine their effects as represented in each model on the two flow regimes using a Corey relative permeability function for oil. Specifically, we plot the pressure-gradient contours that define the two flow regimes as a function of superficial velocities of water, gas, and oil, and show how oil shifts behavior in the regimes.
The wet-foam model shifts behavior in the low-quality regimes with no direct effect on the high-quality regime. The dry-out model shifts behavior in the high-quality regimes but not the low-quality regime. At fixed superficial velocities, both models predict multiple steady states at some injection conditions. We perform a stability analysis of these states using a simple 1D simulator with and without incorporating capillary diffusion. The steady state attained after injection depends on the initial state. In some cases, it appears that the steady state at the intermediate pressure gradient is inherently unstable, as represented in the model. In some cases, the introduction of capillary diffusion is required to attain a uniform steady state in the medium. The existence of multiple steady states, with the intermediate one being unstable, is reminiscent of catastrophe theory and of studies of foam generation without oil.