Abstract Knowing the injection profile of each injector in a reservoir is of major importance for analyzing residual oil distribution underground. However, in practice, it is impossible to acquire real-time injection profiles for each well when they are needed. In this paper, a two-step learning fuzzy system was introduced to predict injection profiles for wells with outdated data or without data by analyzing those injectors whose injection profiles are well characterized. Five pivotal parameters were selected to be fed into the subtractive clustering algorithm and ANFIS (adaptive-network-based fuzzy inference system) to model their non-linear relationships with the injectivity of each producing layer. Experiments in comparing the two-step method and the backpropagate feed-forward (BPFF) neural network showed that the two-step method can automatically generate a more simply structured fuzzy inference system (FIS) and can simulate complicated numerical nonlinear relationships with higher accuracy. This method was used in injection profile prediction in one block of the Daqing oilfield. The average accuracy was shown to be above 80%.
Shale formations in North America such as Bakken, Niobrara, and Eagle Ford have huge oil in place, 100–900 billion barrels of oil in Bakken only. However, the predicted primary recovery is still below 10%. Therefore, seeking for techniques to enhance oil recovery in these complex plays is inevitable. Although most of the previous studies in this area recommended that CO2 would be the best EOR technique to improve oil recovery in these formations, pilot tests showed that natural gases performance clearly exceeds CO2 performance in the field scale. In this paper, two different approaches have been integrated to investigate the feasibility of three different miscible gases which are CO2, lean gases, and rich gases. Firstly, numerical simulation methods of compositional models have been incorporated with local grid refinement of hydraulic fractures to mimic the performance of these miscible gases in shale reservoirs conditions. Implementation of a molecular diffusion model in the LS-LR-DK (logarithmically spaced, locally refined, and dual permeability) model has been also conducted. Secondly, different molar-diffusivity rates for miscible gases have been simulated to find the diffusivity level in the field scale by matching the performance for some EOR pilot tests which were conducted in Bakken formation of North Dakota, Montana, and South Saskatchewan. The simulated shale reservoirs scenarios confirmed that diffusion is the dominated flow among all flow regimes in these unconventional formations. Furthermore, the incremental oil recovery due to lean gases, rich gases, and CO2 gas injection confirms the predicted flow regime. The effect of diffusion implementation has been verified with both of single porosity and dual-permeability model cases. However, some of CO2 pilot tests showed a good match with the simulated cases which have low molar-diffusivity between the injected CO2 and the formation oil. Accordingly, the rich and lean gases have shown a better performance to enhance oil recovery in these tight formations. However, rich gases need long soaking periods, and lean gases need large volumes to be injected for more successful results. Furthermore, the number of huff-n-puff cycles has a little effect on the all injected gases performance; however, the soaking period has a significant effect. This research project demonstrated how to select the best type of miscible gases to enhance oil recovery in unconventional reservoirs according to the field-candidate conditions and operating parameters. Finally, the reasons beyond the success of natural gases and failure of CO2 in the pilot tests have been physically and numerically discussed.
Abstract The oil recovery from fractured reservoirs is usually low and the early water breakthrough is one result of the fractured reservoir. Two enhanced oil recovery (EOR) methods, low salinity water flooding (LSWF) and micro-gel, have recently drawn great interest from the oil industry. We integrated both methods into one process. The objective of this study was to test how the combining method could reduce production rates from the fractured layer and improve the production rate from the non-fractured layer through laboratory experiments. The parallel non-crossflow models, which were made of sandstone cores and two core holders, were built. The gel strength, water salinity, gel particle size, and sandstone permeability effects on oil recovery, production rate, and gel penetrations were studied. Sodium chloride (NaCl) was used for brine flooding and preparing swollen PPG. Two brine concentrations (1.0, and 0.01 wt. % NaCl) were used for the experiments. A light mineral oil was used. A flow rate of 0.5 ml/min. was used to inject the brine into the parallel non-crossflow models before and after the gel was placed into the fracture. The gel was injected into Outlet 1 to fill out the fracture at a flow rate of 2.0 ml/min until the gel injection pressure reached 500 psi. The optimum water salinity for the application of the coupled method was determined through laboratory experiments to be 0.01 wt. % NaCl because this gave the highest gel penetration into the partially fractured layer. However, the best water shut-off was obtained when the water salinity was 1.0 wt. % NaCl. The incremental oil recovery was almost the same in both 1.0 and 0.01 wt. % NaCl water salinity. When the gel particle size decreased, the water shut-off from the partially- closed fracture layer and the incremental oil recovery from the matrix were increased. This application had no significant effect when the core permeability was low because there was not much of an effect on the production rate ratio after gel treatment. From the laboratory experiments, we concluded that the PPG application might be more successful it is swelled in a low brine concentration.
Abstract Polymer bulk gels have been widely applied to mitigate excessive water production in mature oil fields by correcting reservoir permeability heterogeneity. This paper presents a comprehensive review of the water responses and the economic assessments of injection-well gel treatments. The survey includes 61 field projects implemented between 1985 and 2014 and compiled from SPE papers and U.S. DOE reports. Ten parameters were evaluated according to the reservoir lithology, formation type, and recovery process using the univariate analysis, stacked histograms, and scatterplots. Results indicated that gel treatments have very wide ranges of water injection/production responses and economic indicators. We identified that gel treatments do reduce the water production but not dramatically to really low levels. The water production continues to increase after the proactive treatments applied in undeveloped conformance problems at low water cuts (<50%). Contrarily, the water production decreases after the reactive treatments conducted in developed conformance issues at high water cuts (>50%). When successfully applied, gel treatments averagely reduce the water injection rate by 34% and the water cut by 10%; however, the water cut may also increase by 17%. For developed problems, the water cut may stabilize or increase after the remediation mainly in matrix-rock sandstone reservoirs, especially when small gel volumes are injected (<1000 barrels) into this formation type. Economically, gel treatments are appraised solely based on the oil production response and both water responses are not considered in the evaluation. Typically, gel treatments have cost of incremental oil barrel of 2$/barrel and payout time of 9.2 months and function for 1.9 years. They have better water responses and economics in carbonates than in sandstones and in unconsolidated and naturally-fractured than in matrix-rock formations; however, they have reverse tends with respect to the gel effective time. The gel effective time significantly decreases with the channeling strength, the aperture of flow channels, and the temperature of injected drive-fluids. Generally, the water production response and economic parameters improve as the injected gel volume increases and the treatment timing advances in the flooding life. For different application environments, the present review provides reservoir engineers with updated ideas about what are the low, typical, and high performances of gel treatments when applied successfully and how other treatment aspects affect the performances.
Field trials have demonstrated that foamed gel is a very cost-effective technology for profile modification and water shut-off. However, the mechanisms of profile modification and flow behavior of foamed gel in non-homogeneous porous media are not yet well understood. In order to investigate these mechanisms and the interactions between foamed gel and oil in porous media, coreflooding and pore-scale visualization waterflooding experiments were performed in the laboratory. The results of the coreflooding experiment in non-homogeneous porous media showed that the displacement efficiency improved by approximately 30% after injecting a 0.3 pore volume of foamed gel, and was proportional to the pore volumes of the injected foamed gel. Additionally, the mid-high permeability zone can be selectively plugged by foamed gel, and then oil located in the low permeability zone will be displaced. The visualization images demonstrated that the amoeba effect and Jamin effect are the main mechanisms for enhancing oil recovery by foamed gel. Compared with conventional gel, a unique benefit of foamed gel is that it can pass through micropores by transforming into arbitrary shapes without rupturing, this phenomenon has been named the amoeba effect. Additionally, the stability of foam in the presence of crude oil also was investigated. Image and statistical analysis showed that these foams boast excellent oil resistance and elasticity, which allows them to work deep within formations.
In this paper, we propose and numerically solve a new model considering confined flow in dual-porosity media coupled with free flow in embedded macrofractures and conduits. Such situation arises, for example, for fluid flows in hydraulic fractured tight/shale oil/gas reservoirs. The flow in dual-porosity media, which consists of both matrix and microfractures, is described by a dual-porosity model. And the flow in the macrofractures and conduits is governed by the Stokes equation. Then the two models are coupled through four physically valid interface conditions on the interface between dual-porosity media and macrofractures/conduits, which play a key role in a physically faithful simulation with high accuracy. All the four interface conditions are constructed based on fundamental properties of the traditional dual-porosity model and the well-known Stokes--Darcy model. The weak formulation is derived for the proposed model, and the well-posedness of the model is analyzed. A finite element semidiscretization in space is presented based on the weak formulation, and four different schemes are then utilized for the full discretization. The convergence of the full discretization with the backward Euler scheme is analyzed. Four numerical experiments are presented to validate the proposed model and demonstrate the features of both the model and the numerical method, such as the optimal convergence rate of the numerical solution, the detail flow characteristics around macrofractures and conduits, and the applicability to the real world problems.
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