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The goal of this work is to study foam stabilization by in-situ surface activation of hydrophilic nanoparticles for subsurface applications. The interfacial properties of the nanoparticles were modulated by attachment of short chain surface modifiers which render them partially hydrophobic. Static foams were generated using nanoparticles with varying concentrations of surface modifiers. The decay of foam height with time was studied and half-lives were determined. Optical micrographs of foams stabilized by surface-modified nanoparticles (SM-NP) and surfactants were recorded. Aqueous foams were created in-situ by co-injecting the SM-NP solutions with nitrogen gas through a Berea sandstone core at a fixed quality. Pressure drop across the core was measured to estimate the achieved mobility reduction factor (MRF). The results were then compared with a typical surfactant under similar conditions. Oil displacement experiments were conducted in Berea cores using surfactant and SM-NP solutions as foaming agents. Bartsch shake test revealed strong foaming tendency of SM-NP even with a very low initial surface-modifier concentration (0.05 wt%), whereas hydrophilic nanoparticles alone could not stabilize foam. The bubble texture of foam stabilized by SM-NP was finer than that with surfactant which indicated a stronger foam. As the degree of surface coating increased, mobility reduction factor (MRF) of SM-NP foam in a Berea core increased significantly. The core floods in the sandstone cores with a reservoir crude oil showed that immiscible foams using SM-NP solution can recover significant amount of oil over water flood.
With the surging energy demand and consumption globally, there is an inevitable need to exploit the existing oil reserves efficiently. Pressure depletion (primary), water flooding, and gas drainage (secondary) are the common techniques that are employed to recover oil, but more than half of the original oil is still left behind in reservoirs (Mohanty, 2003). Enhanced oil recovery (EOR) techniques like miscible gas injection, chemical flooding, and thermal recovery are being developed to recover the residual oil. Gas flooding is one of the most accepted and widely applied EOR method (Orr, 2007). It comprises injection of hydrocarbon components like methane, propane and enriched-gases, and non-hydrocarbon components like carbon dioxide (primarily), nitrogen and flue gas into oil reservoirs that have been typically waterflooded. CO2 flooding is now quite environmentally and economically feasible due to current high oil prices and availability of large anthropogenic CO2 sources through carbon capture (Enick et al., 2012). In principle, gas flooding is quite effective in improving microscopic sweep efficiency (Lake, 1989). In fact, if the gas is first or multicontact miscible with the oil, it can displace virtually all the oil in the volume swept by the gas (Orr et al., 1982). However, the volumetric sweep efficiency of gas flood is often very poor due to reservoir heterogeneity, gravity segregation, and viscous instability.
In alkali surfactant polymer (ASP) floods, alkali reduces surfactant adsorption and forms in situ surfactant with active oils, thus reducing synthetic surfactant requirement. Many reservoirs, especially carbonates, contain gypsum or anhydrite. In such cases, a conventional alkali like sodium carbonate cannot be used in ASP formulations because it precipitates as calcite. However, it was found that the calcium concentration in the presence of gypsum can be as high as 2000 ppm without causing any precipitation when ammonia is used as the alkali. Ultralow IFT surfactant formulations were obtained in the presence of up to 1200 ppm Ca2+. Propagation of high pH, good oil recovery and low surfactant retention were observed in an ASP coreflood performed in a carbonate core containing gypsum. The Phreeqc geochemical simulator was used for reactive transport modeling and was found to be an effective tool for designing these corefloods. A good match was observed between the measured concentration of the effluent ions from a coreflood experiment and the Phreeqc simulations.
After primary and secondary recovery in oil reservoirs, a large amount of residual oil is unrecovered due to trapping in the pores of the reservoir rock by capillary forces. Surfactants are able to mobilize this trapped oil by lowering the interfacial tension. Surfactants are retained in the reservoir by various mechanisms such as adsorption on mineral surfaces and phase trapping (Solairaj et al., 2012). Since a limited amount of surfactant can be used for an economical flood, the surfactant retention needs to be minimized. One of the ways of doing this is by incorporating an alkali into the surfactant formulation to increase the pH, which reduces the adsorption of anionic surfactants by making the surface charge negative (Somasundaran, 1979; Hirasaki et al., 2008). Alkali also helps in minimizing the amount of surfactant needed for oils that contain organic acids by generating soap.
Many carbonate reservoirs contain either gypsum or anhydrite. Levitt et al. (2011) discuss various challenges encountered in the application of chemical EOR in carbonate reservoirs, especially in the presence of gypsum. Gypsum (CaSO4.2H2O) or anhydrite (CaSO4) differ in the water of hydration. The transition from gypsum to anhydrite takes place around 45 °C. Gypsum (or anhydrite depending on the temperature, but for convenience we refer to gypsum unless we are describing a specific instance of anhydrite) is commonly present in carbonate reservoirs, especially dolomite formations as well as some sandstones, but it is less common in sandstone reservoirs. Under these circumstances, a conventional alkali such as sodium carbonate cannot be used because of precipitation of calcite by the reaction,
With the development of unconventional shale and tight reservoirs, stimulation treatments that place multiple transverse fractures have received a greater attention in recent years. The post-frac productivity of such low-permeability reservoirs is largely determined by the matrix-fracture contact area with appropriate fracture conductivity. Although it is often anticipated that the fractures are infinitely conductive, the general belief is that the production increases with the proppant amount injected.
This paper presents an approach to assess the optimum proppant amount injected by determining the post-frac conductivity. First, using three-dimensional finite difference reservoir simulations in a naturally fractured reservoir, which has both the hydraulic fracture and natural fractures modeled explicitly as discrete grid blocks, we find cumulative production as a function of fracture conductivity. For a fixed propped length and production time, we observe a critical conductivity beyond which the production is insensitive to the conductivity. The critical conductivity is then obtained as a function of the propped length and production time. The numerical results show that the critical conductivity increases with propped length and decreases with production time. The effect of stimulated natural fracture properties (intensity and permeability) on the critical conductivity is then investigated. For reservoirs with matrix permeability in the range 20-1000 nD, natural fractures increase the short-term critical conductivity but decrease the medium to long-term ones. The paper also evaluates the influence of water production, cluster spacing, and BHP flowing pressure on the critical conductivity.
This study demonstrates that Agarwal type curves based on linear flow are not appropriate for naturally fractured reservoirs and lead to errors in estimation of critical conductivity. The results of this study can be useful for selecting the type and amount of proppant for stimulation of unconventional reservoirs.
Recent advances in horizontal drilling and hydraulic fracturing have enabled economic production from North American shale and tight reservoirs. These include multi-stage fracturing using plug-and-perf method, use of slickwater as fracturing fluid and various completion tools. Due to low recovery factors and fast declining rates, well productivity in such low-permeability reservoirs is driven by the stimulation effectiveness to create a large matrix-fracture contact area. Therefore, optimizing the completions parameters (stage spacing, proppant and fluid type, open-hole vs. cemented etc.) has become an integral part of the field-development program.
Shale reservoirs are complex, heterogeneous and often characterized by the presence of natural fractures, faults and planes of weakness. The interactions between hydraulic and natural fractures can lead to non-planar, complex fracture growths. However, such network growth is not fully understood and the field validation has been challenging. Although microseismic measurements have provided some insight into the complex fracture network growth (King 2010), microseimics can only capture a small portion of rock deformation and cannot provide any information about proppant and conductivity distribution (Cipolla and Wallace, 2014). Diagnostic tools such as production logs, fiber optics, tracers etc. are often qualitative and severely limited by non-uniqueness of the interpretation. In addition, the accuracy of current fracture models to simulate the network fracture growth is limited to only 2D (McClure 2014) and pseudo-3D models (Weng et al., 2011; Meyer et al. 2013). All these factors have made completion engineers to choose the optimization parameters based on ad-hoc, trial-and-error approaches.
An equation-of-state based compositional reservoir simulator, UT-COMP, is used to simulate the improved oil recovery by CO2 huff-n-puff in a shale matrix typical of the Bakken Formation. Non-aqueous components are carefully lumped into seven pseudo components. Permeability fields with various heterogeneity and correlation lengths are generated. UT-COMP is able to solve the compositional model, despite the permeability difference between the fracture and matrix being six orders of magnitude. Multiple cycles of CO2 huff-n-puff are simulated and compared with production by primary depressurization. The oil is first contact miscible with the injected CO2 under the reservoir pressure. Simulations show that primary recovery outperforms CO2 huff-n-puff in an ideally homogenous reservoir because injected CO2 moves deep into the reservoir without much increase in near-well pressure, while CO2 huff-n-puff outperforms primary recovery if there exists a low-permeability region which keeps CO2 in the near-well bore injection region. In the latter case, the final recovery using CO2 huff-n-puff is higher than that from primary depressurization; the recovery in a single cycle is about 3.3%, which increases to 3.5% in about 3 cycles. The recovery factor after 1000 days by primary depressurization with production pressure of 1000 psi is 11.6%, which is in agreement with existing studies. The recovery increase can be fit by a two-parameter exponential function and the rate coefficient is found to be insensitive to correlation length, while depends mainly on reservoir heterogeneity. A linear relationship between heterogeneity and rate coefficient is obtained. This work is the first to investigate the effect of heterogeneity on improved hydrocarbon recovery by CO2 huff-n-puff, and will be valuable in understanding the coupling between shale properties and oil recovery.
Carbonate reservoirs have complex pore structure and tend to be oil-wet. The remaining oil saturation is often high after a gas flood. The goal of this work is to develop and evaluate surfactant formulations that can improve the oil recovery after a gas flood. An anionic surfactant was used to develop a low IFT and wettability altering formulation for a soft injection brine and EDTA was added to modify the formulation for a hard injection brine. These surfactant solutions changed the wettability of an oil-wet calcite plate to intermediate-wet/water-wet conditions. Core spontaneous imbibition tests and corefloods were conducted. These displacements were simulated using CMG-STAR to study in-situ viscous fingering during gas injection and improved oil recovery using surfactant formulations. The hard brine surfactant formulation recovered 54% of the original oil in 60 hours by spontaneous imbibitions compared to 12% for the soft brine surfactant formulation and no oil for the formation brine. Initial gas flood left a lot of oil unswept. EDTA assisted hard brine surfactant formulation could recover over 40% of the oil, higher than 25% for the soft brine surfactant formulation. The gas injection after the surfactant slug increased the pressure drop due to foam formation. Numerical simulation of the GSG flood showed in-situ viscous fingering during the first gas injection and efficient oil displacement during the surfactant injection and the subsequent gas injection.