Reichenbach-Klinke, Roland (BASF Construction Polymers GmbH) | Stavland, Arne (International Research Institute of Stavanger) | Langlotz, Bjorn (BASF Construction Chemicals GmbH) | Wenzke, Benjamin (BASF SE) | Brodt, Gregor (BASF SE)
New thickeners based on associative properties and their application in enhanced oil recovery are discussed. The new thickeners are anionic, water-soluble, hydrophobically modified copolymers.
The rheological properties as well as the flow properties in porous media have been evaluated. In bulk the polymer viscosity is shear thinning and the viscosity vs. shear rate profile is comparable with other synthetic EOR polymers. For most of the other tested parameters, the new thickeners differ from what is assumed as the standard properties for EOR polymers. The relative viscosity increases by increasing the temperature, especially at low shear rates. The core flood experiments revealed a significant mobility reduction in sandstone cores, both at ambient and elevated temperature. The mobility reduction demonstrated strongly shear thinning behavior. For standard EOR polymers the main contribution to the mobility reduction and improved mobility ratio is the polymer viscosity, while for the new thickeners the mobility reduction seems to be dominated by reversible polymer retention that is lowering the permeability. Post water injection resulted in low permeability reduction. However, the time to regain the permeability was significant.
Flood experiments with the associative polymer in Bentheim sandstone cores showed significantly increased oil production. The incremental oil recovery was interpreted by the capillary number which due to the high mobility reduction exceeded the critical capillary number. Because of the high mobility reduction a further increase in oil production would have been possible by only slight reduction of the oil-water interfacial tension by addition of small amounts of a surfactant. Moreover the new associative polymer seems to be more shear stable than other synthetic EOR polymers.
Foam improves sweep in miscible and immiscible gas-injection EOR processes. "SAG" foam processes (injecting alternating slugs of surfactant solution and gas) offer many advantages over co-injection of foam for both operational and sweep-efficiency reasons. The success of a foam SAG process depends on foam behavior at very low injected water fraction (high foam quality), which means that fitting data to a typical scan of foam behavior as a function of foam quality can miss conditions that determine the success of a SAG process. The result can be inaccurate scale-up of results to field application. A successful SAG foam process depends on behavior at very low fractional flow during gas injection and on behavior at larger water fractional flow further from the well where gas and surfactant slugs mix.
We illustrate how to fit foam-model parameters to steady-state foam data for application to SAG foam processes. Dynamic SAG corefloods can be unreliable because of failure to reach local steady state (because of slow foam generation), the increased effect of dispersion at the core scale, and the capillary end effect. For current foam models the behavior of foam in SAG depends on the mobility of full-strength foam, the capillary pressure or water saturation at which foam collapses and the parameter governing the abruptness of this collapse. We illustrate how to fit these model parameters to coreflood data, and the challenges that can arise in the fitting process, using the published foam data of Persoff et al. (1991) and Ma et al. (2012). For illustration we use the foam model in the widely used STARS simulator. Having accurate water-saturation data is essential to making a reliable fit to the data. Model fits to a given experiment may result in inaccurate extrapolation to mobility at the wellbore and therefore predicted injectivity: for instance, a model fit in which foam does not collapse even at the extremely large capillary pressure at the wellbore.
We show how the insights of fractional-flow theory can guide the model-fitting process and give quick estimates of foam propagation rate, mobility and injectivity at the field scale.
Screening for Enhanced Oil Recovery (EOR) processes is a critical step in evaluating future development strategies for depleted reservoirs under primary and secondary recovery. However, selecting the optimum EOR process for a given reservoir is challenging because it requires evaluating and comparing performance for various EOR processes, which is complex and time consuming.
This paper presents a new EOR screening model that can predict the performance of various gas- and water-based EOR processes based on simple reservoir properties. The model estimates the oil recovery from miscible and immiscible gas/solvent injection (CO2, N2, and hydrocarbons), low salinity water flood, polymer, surfactant-polymer, alkaline-polymer and alkaline-surfactant-polymer floods. The screening model is based on a set of correlations that were developed using the response surface methodology, which correlates the oil recovery at dimensionless times to the important reservoir and fluid properties and EOR process variables identified for each process. The results of the model have been validated against a number of field test and numerical simulation results.
The screening model provides the capability to screen a large set of reservoirs for a wide spectrum of EOR processes, to identify the good EOR targets and the optimum EOR process for the target reservoirs. In addition, this model easily performs sensitivity analysis without the need for numerical simulations, allowing teams to account for uncertainty in reservoir properties and optimization of flood design. Finally, the methodology can be applied for developing screening models for other oil recovery mechanisms such as thermal (steam injection, SAGD), microbial EOR and other methods.
Current global demand for fossil fuel such as oil is still high. This encourages oil and gas industries to improve their effort of finding new discoveries, developing technique and maximizing recovery of their current resources including in low-permeability reservoir. Enhanced oil recovery (EOR) is a technique to enhanced ultimate recovery. Since technology has been continuously developed such as nanotechnology/nano-size material, EOR methods have improved. One of them is Nano-EOR that triggered great attention in last decade. Nanoparticles may alter the reservoir fluid composition and rock-fluid properties to assist in mobilizing trapped oil. Most of observation from lab-scale reported that it seems potentially interesting for EOR.
Since reservoir management is very essential for the success of all improved/enhanced oil recovery (IOR/EOR) methods, optimizing nanofluids concentration is a proposed reservoir management to maximize oil recovery using Nano-EOR in this paper. Low-permeability water-wet Berea sandstones core-plugs with porosity ranged 13-15% and permeability ranged 5-20 mD were tested. A hydrophilic silica nanoparticles with primary particle size 7 nm was employed without surface treatment. Nanofluids with various concentration ranged 0.01 - 0.1 wt.% were synthesized with synthetic saline water for optimizing study. The wettability alteration due to nanofluids was observed; coreflood experiment was conducted and compared its displacement efficiency.
The results observed a range of nanofluids concentration that could maximize oil recovery in low-permeability water-wet Berea sandstone. Although contact angle of aqueous phase decreases as nanofluids concentration increase which means easier of oil to be released but we observed that higher concentration (e.g. 0.1 wt.%) has a tendency to block pore network and will decrease or even without additional oil recovery.
This study provides if concentration of nanofluids has an important parameter in Nano-EOR and could be optimized to maximize oil recovery of low-permeability water-wet Berea sandstone.
Experiments involving three-phase flow in porous media including Water-Alternating-Gas (WAG) injection are time-consuming andexpensive. Therefore, it is not feasible to experimentally consider all alternative injection schemes of these processes for different wettability and IFT (interfacial tension) conditions. The standard approach is to perform numerical simulations using models preferably tuned by laboratory data and experiments.
We present the results of a series of two-phase (WF and GF) and three-phase (WAG and SWAG) coreflood experiments performed in both water-wet and mixed-wet rocks. The objective of the experiments was to understand the impact of wettability and injection strategy, as well as generating reliable data for tuning a simulation model. A numerical model was developed and validated via experimental results under both wettability conditions, and then used to investigate the effect of a large number of parameters including; WAG starting time and slugsizes well as oil/gas IFT and wettability on the performance of different injection scenarios.
The results show that for water-wet systems, the highest oil recovery is achieved by SWAG (Simultaneous Water and Gas) and WAG injections and the poorest injection scheme is primary WF (water flood), whereas in the mixed-wet system, WAG and SWAG are the best and worst injection scenarios, respectively. In water-wet systems, the SWAG performance improved by increasing the ratio of gas to water while in mixed-wet systems, SWAG performance decreased by increasing gas to water ratio. Under water-wet conditions, better performance was achieved by smaller WAG slug sizes (higher number of WAG cycles) but for mixed-wet systems WAG performance decreased with increasing the number of the cycles. Our results also show that under near-miscible oil/gasconditions (IFT = 0.04 mN.m-1), the oil recovery by primary GF (Gas Flood) was much higher for water-wet systems compared to the mixed-wet conditions. Although the same trend has been observed for the immiscible condition (IFT = 9.4 mN.m-1), but under immiscible conditions the difference between the performance of GF for the two wettabilities(water-wet and mixed-wet) is not significant.For all oil/gas IFT values tested, WAG performance was found to be higher in mixed-wet systems compared to their water-wet counterparts, however, the effect of wettability was more pronounced in higher gas/oil IFT conditions. For both wettability conditions, starting WAG before water breakthrough of theprimary WF increased oil recovery.
Various techniques of Enhanced Oil Recovery (EOR) exist and amongst them water and gas injection are the most widely used. It has been shown that combining water and gas injection in a WAG (water alternating gas) scheme can result in additional oil recovery. Interest in WAG injection has increasingly grown in recent times with many reservoirs around the world now under WAG injection.
Numerical simulation of WAG requires reliable three-phase relative permeability and hysteresis data which are normally obtained from models available in commercial simulators. This paper utilizes core-flood experimental data from literature to investigate validity of these models.
The findings from this study provide evidence that different three-phase relative permeability models were found to behave differently giving varying recovery factors in a WAG simulation scheme. While the effect of irreversible hysteresis was studied, it was observed here that imbibition (stage I) and drainage (stage II) processes gave results that deviated from conventional hysteresis. Simulations were run with and without hysteresis for different three phase relative permeability models with different effects observed for the recovery factor.
The results of this work show that a good understanding of the three phase relative permeability model in use is very important for a more robust reservoir simulation model. Also, the effect of irreversible hysteresis in WAG injection should be adequately modelled in order to obtain reliable results. Lastly, the results reveal the importance of optimum WAG ratio for maximizing oil recovery by preventing a gas tongue forming at the top of the reservoir and a water tongue forming at the bottom of the reservoir.
Humphry, Katherine Jane (Shell Global Solutions International) | van der Lee, Merit (Shell Global Solutions International) | Southwick, Jeff G. (Sarawak Shell) | Ineke, Erik M. (Shell Global Solutions International) | van Batenburg, Diederik W (Shell Global Solutions International)
Workflows to assess the technical and economic suitability of an enhanced oil recovery (EOR) technique for a particular field generally involve laboratory testing, such as core flooding experiments, and field-scale reservoir modelling. When building field scale models and interpreting laboratory experiments it is important to understand the flow properties of all phases present.
Alkali-surfactant-polymer flooding (ASP) is an EOR technique under consideration for a number of Malaysian oil fields. In ASP flooding, surface-active molecules decrease the interfacial tension between water and crude oil, increasing the capillary number, and recovering oil trapped in the reservoir pores. The ultra-low interfacial tensions needed for ASP flooding occur when the surface active molecules are equally soluble in the brine and oil phases. Under these conditions, in addition to the brine and oil phases, a third thermodynamically stable phase is formed. This third phase is known as a microemulsion. While the flow properties of crude oil and polymer-enriched brine are well understood, little has been done to characterize the microemulsion phase, particularly with respect to rheology in porous media.
Here, preliminary measurements of microemulsion rheology are presented. Large volumes of microemulsion, with and without polymer, are generated using model alkali-surfactant (AS) and alkali-surfactant-polymer (ASP) systems. These microemulsions are studied using conventional shear rheology. The viscosities measured using a conventional shear rheometer indicate microemulsion viscosities higher than either the AS(P) solution or decane from which they are comprised. Additionally, an in situ, or apparent, viscosity is recovered from core flooding experiments in Berea sandstone, where pressure drop across the core is recorded as a function of the flow rate of the microemulsion through the core. In situ viscosity measurements in Berea sandstone indicate apparent viscosities 1.5 to 6 times larger than those measured in a conventional shear rheometer. The implication of these results for ASP flooding is discussed.
As part of the development planning of an alternating water and gas injection scheme for Enchance Oil Recovery in the Bokor Field, a risk evaluation study was carried out to assess the likelihood of injection gas migration from the reservoir to the
seabed. This hazard was identified as a principal HSE risk to the platform installations by the Bokor Field development team. A work flow was constructed which involved the integration of geological and petrophysical based seal evaluations with
coupled fluid-stress geomechanical modeling of the depletion and injection processes over the life of the field to determine reservoir shale seal efficiency and gas leakage risks due to both hydraulic fracturing and fault reactivation. The coupled
geomechanical modeling process incorporated, not only the resulting pressure changes arising due to depletion and injection within the reservoir, but also utilized a consolidation scheme to model the imposed pore pressure changes within the
overburden arising due to stress transfer, and the subsequent dissipation of these excess pore pressures with time. Evidence of fault related gas migration in the geological past is seen by the presence of a shallow gas cloud identified on seismic data sitting above the crest of the structure. The scope of the study included the evaluation of this cloud on various vintages of seismic from 1976 to 2011 to determine whether the size and geometry of the gas cloud was related to previous field development.
The study clearly demonstrates the application of coupled geomechanical modeling in assessing surface and subsurface risks resulting from field development.
Prior to any EOR application, quantifying the remaining oil saturation (ROS) after water flood is critical in order to establish the target oil for a potential EOR scheme. The most widely available datasets for quantifying ROS are from the saturation logs such as resistivity logs from infill wells and pulsed neutron capture (PNC) logs from cased wells. However, the interpretation of these logs generally requires prior knowledge of water salinity. In most water flood projects, the injected water is different from the formation water, and the salinity is unknown in the water flooded zones. Logging tools for saturations without prior knowledge of salinity, such as the C/O log, also have limitations.
The current practice to overcome this problem is to apply one or more of the following techniques:
• Chemical tracer
• Sponge coring, pressurized coring, etc.
However, these techniques are relatively expensive and time-consuming. They cannot be used routinely field wide as a reservoir surveillance tool.
In this paper, we present a methodology to reduce the uncertainties in saturation logs within the context of reservoir model history-matching. In addition to matching pressure and water cut, the new methodology seeks to match the produced water chemistry too (with formation water and injection water chemistry as inputs). This is due to the recent advance of reservoir simulations that can model reservoir water composition changes by considering geochemical reactions of injection waters, formation brine, and reservoir minerals. With this new simulation capability, resistivity and sigma values per grid block are computed as part of the simulation, thus pseudo-logs of total resistivity and neutron capture cross section (S) can be generated as part of the simulation. This enables direct history-matching of the measured log signals.
For an EOR project, the implication of this new simulation methodology is to encourage the frequent sampling and analysis of injection and produced water as part of the reservoir surveillance, and run resistivity and/or S logs to monitor saturation changes even when injection water is significantly different from formation water.
Determination of swept volume is important for evaluation of a thermal project. Thermal well testing offers a simple method to estimate the steam zone properties using pressure falloff tests. A composite reservoir model is assumed with two regions of highly contrasting fluid mobilities and the flood front as an impermeable boundary. The swept zone therefore acts as a closed reservoir and pressure response is characterized by pseudo steady state behavior.
Most of the previous studies have considered vertical wells because of the simpler method of well test analysis compared to horizontal wells. However, a steam assisted gravity drainage (SAGD) process using horizontal well pairs is a promising technique in heavy oil recovery.
The applicability of thermal well test analysis in estimating the swept zone properties for vertical and horizontal wells was thoroughly investigated in this study. A thermal simulator was used to simulate pressure falloff tests. The generated pressure data were then analyzed to calculate swept volume and reservoir parameters. Properties of an Athabasca heavy oil sample, measured in the lab, were used as input for numerical simulation purposes.
Results of this work show good agreement between the calculated and simulated values of swept volume, swept zone permeability and skin factor for both vertical and horizontal wells. Estimations depend on the vertical position of the pressure gauge. Effects of gravity, swept region shape, dip, steam quality, steam injection rate, injection time, permeability anisotropy and gridblock density on the results were also investigated. Higher injection rates and longer injection times lead to poorer estimates of the swept volume because of a more irregular shape of the swept region and the possibility of earlier breakthrough. Vertical and lateral distances between the horizontal injector and producer affect the estimation of swept volume. Isotropy and grid refinement do not necessarily improve the estimations.