Shiau, Bor Jier Ben (University of Oklahoma) | Hsu, Tzu-Ping (University of Oklahoma) | Lohateeraparp, Prapas (University of Oklahoma) | Rojas, Mario R. (University of Oklahoma) | Budhathoki, Mahesh (University of Oklahoma) | Raj, Ajay (University of Oklahoma) | Wan, Wei (University of Oklahoma) | Bang, Sangho (University of Oklahoma) | Harwell, Jeffrey H. (University of Oklahoma)
Reservoirs containing very high total dissolved solids and high hardness make the design of a surfactant polymer (SP) flood extremely difficult because surfactant tends to precipitate and separate under these conditions. Beside divalent ions, Ca2+, Mg2+, presence of iron in the brine can be a challenging issue. Different surfactant formulations are evaluated and incorporate cosurfactants and co-solvents which minimize viscous macroemulsions, promote rapid coalescence under Winsor Type III conditions, and stabilize the chemical solution by reducing precipitation and phase separation. The optimal surfactant formulations were further evaluated in one-dimensional sand packs and coreflood tests using Berea sandstone, reservoir oils, and brines at reservoir temperatures. Using similar injection protocols, 3 pore volumes of surfactant-only system, experimental results show the oil recovery ranging from 45 % to 70% of the residual oil (Sor) after water flooding. The level of surfactant loading is less than 0.5 wt%. A single-well test was conducted to confirm laboratory results in situ in the presence of high-salinity formation water containing 102,300 mg/L total dissolved solids (TDS). The aim of ongoing test is to confirm the effectiveness of the high-salinity surfactant-only formulation (0.46 wt% of surfactant). In this effort, we plan to conduct multiple single-well tests at different wells to minimize the design risks involved for the surfactant pilot test. A pilot test at a sandstone reservoir is scheduled to be performed in July of 2013 to further evaluate the effectiveness of surfactant formulation and address technical issues related to scale-up.
Although more emphasis is placed on the interaction between CO2 and oil during a CO2 injection process, the interaction of CO2 with the reservoir brine, too, could be significant in terms of its impact. This study presents a modeling approach to evaluate the possible effects of brine salinity on CO2 injection in the context of both CO2 injection and low-salinity waterflood.
In the first phase of the study, the relevant correlations widely reported in the literature were applied for investigation of brine salinity effects on CO2-brine system properties for carbonate reservoir conditions at 248°F (120°C) and 3000psi (20.68MPa). The properties investigated include CO2 solubility in brine, IFT between CO2 and CO2-saturated brine, and density and viscosity of CO2-saturated brine. Some relevant experimental data were also incorporated in the validation of these correlations. In the second phase, a simple pore-scale model was developed to evaluate the brine salinity effect on water-isolated oil recovery by CO2 diffusion through water barrier. Furthermore, compositional reservoir simulation using a hypothetical geological model and a real PVT model was conducted to study the brine salinity impact on oil recovery of carbonated-water injection (CWI). The following findings were noted:
(1) Under our reservoir conditions, lowering the brine salinity could significantly enhance CO2 dissolution in brine, consequently leading to great variation of the system properties, which may make a big difference on CO2 injection performance.
(2) The CO2 diffusion-controlled modeling showed that reduction of the salinity in the water, which acted as a barrier blocking the direct contact between CO2 and oil. This could greatly promote the rate and amount of CO2 mass transfer through water barrier to the bypassed oil.
(3) Oil recovery results from simulation studies illustrated that increasing the CO2 solubility by reducing injected brine salinity during carbonated water injection could remarkably ameliorate its performance.
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.
Uribe Hidalgo, Carlos Andres (Universidad Industrial de Santander) | Munoz Navarro, Samuel Fernando (Universidad Industrial de Santander) | Oliveros Gomez, Luis Roberto (Universidad Industrial de Santander) | Naranjo Suarez, Carlos Eduardo (Ecopetrol S.A)
Copyright 2013, Society of Petroleum Engineers This paper was prepared for presentation at the SPE Enhanced Oil Recovery Conference held in Kuala Lumpur, Malaysia, 2-4 July 2013. This paper was selected for presentation by an SPE program committee following review of information contained in an abstract submitted by the author(s). Contents of the paper have not been reviewed by the Society of Petroleum Engineers and are subject to correction by the author(s). The material does not necessarily reflect any position of the Society of Petroleum Engineers, its officers, or members. Electronic reproduction, distribution, or storage of any part of this paper without the written consent of the Society of Petroleum Engineers is prohibited. Permission to reproduce in print is restricted to an abstract of not more than 300 words; illustrations may not be copied. The abstract must contain conspicuous acknowledgment of SPE copyright.
Buijse, Marten Adriaan (Shell Exploration & Production) | Tandon, Kunj (Shell Technology Centre Bangalore) | Jain, Shekhar (Shell Technology Centre Bangalore) | Jain, Amit (Shell Technology Centre Bangalore) | Handgraaf, Jan-Willem (Culgi B.V.) | Fraaije, Johannes G. E. M. (Leiden University)
Surfactant formulations are extensively being developed in the oil industry for Enhanced Oil Recovery (EOR) applications. Surfactants suitable for EOR will form an oil-brine microemulsion (µE) with ultra-low interfacial tension (IFT), necessary for
high recovery factors. Experimental screening of surfactants, to identify suitable formulations for reservoir conditions, is a laborious and time consuming process. In this paper we demonstrate an alternative, and novel, molecular modeling approach which is suitable for predicting µE properties and calculating optimum conditions. The molecular modeling simulations are based on the recently developed Method of Moments (MoM). The µE physics underlying the MoM is briefly reviewed in this
In the MoM the bending properties of the interfacial surfactant film are calculated as moments of the lateral stress profile. At optimum salinity the zeroth and first moments of the lateral stress profile are zero and the IFT will reach a minimum. In addition to optimum salinity, the bending rigidity (stiffness) of the surfactant film is another interesting microstructure property. The bending rigidity determines the oil/brine domain size, solubilization and magnitude of the IFT. The bending rigidity is accessible in the MoM via the saddle-splay modulus ks, which is calculated as the second moment of the lateral stress profile. It is shown in the paper how the shape of the lateral stress profile depends on molecular properties of the surfactant and on salinity.
MoM simulations were carried out using the coarse-grained Dissipative Particle Dynamics (DPD) method. This computational approach is highly scalable, while preserving the structural information of chemical components in the system. This makes the method useful while screening the wide design space of possible surfactant-oil-brine combinations. We will discuss the predictive technique and some validation examples of predicting optimum salinity for oil-brine micro-emulsions. We will then demonstrate the effect of surfactant structural parameters like chain length, cosolvent etc. on the optimum salinity of the microemulsions.
The paper presents compositional simulation studies of miscible water-alternating-gas (WAG) flooding in stratified reservoirs with respect to compositional variation with vertical depth and temperature. Two series of fluid system were selected from fifth and third SPE comparative study for Reservoir-A and Reservoir-B respectively. The Reservoir-A is an undersaturated black oil reservoir and has initial gas-oil ratio (GOR) of 557 scf/stb. Meanwhile Reservoir-B is near-critical oil reservoir with initial GOR of 3519 scf/stb. The minimum miscible pressure (MMP) variation with depth was calculated using equation of state in both reservoirs. In this study, temperature gradient sensitivity is ranging from 10 to 30 oF per 1000 ft for both active and passive thermal gradient.
The existence of thermal diffusion in WAG process is also discussed. It is investigated that active and passive thermal gradient will give opposite composition variation trend. In active temperature gradient, the amount of light components will increase and heavy components will opposite with respect to depth. Unlike active thermal gradient, the gravity isothermal and passive thermal gradients segregate the heavy components toward the bottom.
The initial oil in place (IOIP) varies due to compositional variation which is again due to gravity and thermal gradients. These issues should be even more obvious when we have oil reservoir with higher GOR or near-critical reservoir. In these particular reservoirs, the presence of gravity and passive thermal gradients will decrease IOIP calculation whereas both reservoirs will have less C7+ components than in basecase. Otherwise, considering thermal diffusion effect by applying active thermal gradients will increase IOIP.
Several parameters were also evaluated during WAG process in both reservoirs such as: various hydrocarbon injection gases, cyclic injection scheme, WAG cycle and ratio, and reservoir heterogeneities. Therefore the effect of compositional variation due to gravity and thermal gradients can be conclusively evaluated.
In CO2 projects for enhanced oil recovery (EOR) a critical factor is possible early CO2 breakthrough and consequently poor sweep efficiency. Injection of foam can block and divert CO2 which may improve sweep efficiency.
Large changes in physical properties of CO2 with temperature and pressure might affect CO2-foam performance under various reservoir conditions. Recently, we have focused on understanding supercritical CO2-foam properties and this paper describes the importance of supercritical CO2 density on CO2-foam performance in outcrop Berea sandstone core material.
Foam flooding experiments were conducted in sandstone core material at different pressures from 30 to 280 bar and at temperatures of 50 and 90°C using an AOSC14/16 surfactant. Results showed high foam strengths at low CO2 density. In fact, the strongest supercritical CO2-foam was generated at the lowest supercritical CO2 density tested, quite comparable to foam strength obtained with gaseous CO2. Only reduced foam strengths were found with dense supercritical CO2 (MRF 3-11).
Foam generation was studied with both equilibrated and non-equilibrated fluids. Previously, we showed that CO2-foam stability and blocking ability were strongly reduced when mass transfer occured. In this study delay in foam strength build-up was observed with non-equilibrated fluids. In addition, visual observations of the foam texture indicated larger bubbles.
Compared to N2-foams at similar conditions CO2-foams were weaker and showed coarser foam structure.
Wan Daud, Wan Ata (Exploration and Production Technology Centre, PETRONAS) | Sedaralit, Mohd Faizal (PETRONAS) | Wong, Fadhli (PETRONAS) | Affendi, Amierul Redza (Exploration & Production Technology Centre. PETRONAS)
With declining oil production, the Exploration & Production companies are in search of applying innovative methodologies to improve recovery factors from existing fields. Immiscible Water Alternating Gas (IWAG) has been identified as one of the enhanced-oil recovery techniques for offshore Dulang oil field in Malaysia. The field redevelopment FDP study was initiated in 2007 to evaluate the optimum recovery scheme to increase oil production from all reservoirs in Dulang field. Results from the simulation study indicated that the major reservoirs will benefit from IWAG injection, with ultimate recovery as high as 50% in some reservoirs. Phase 1 of IWAG injection was started in April 2012
Prior to IWAG field implementation, extensive surveillance program was developed to ensure requires data is captured for monitoring the success of the project and provide a feedback for improvement.
This paper explores the selection of tools and testing programs adopted in surveillance program which include Integrated Operation (IO) for IWAG injection in the Dulang field. The new proposed surveillance program is expected to improve water flood and IWAG monitoring;
The new IWAG surveillance program with the IO system will enable the surveillance team to move from reactive to a proactive asset management system. Real time data will enable engineers to know the status of injection facilities, well status and rate and the performance of IWAG EOR in Dulang.
Ma, Kun (Rice University) | Farajzadeh, Rouhi (Shell Global Solutions International) | Lopez-Salinas, Jose L. (Rice University) | Miller, Clarence A. (Rice University) | Biswal, Sibani Lisa (Rice University) | Hirasaki, George J. (Rice University)
In the absence of oil in the porous medium, the STARSTM foam model has three parameters to describe the foam quality dependence, , , and . Even for a specified value of , two pairs of values of and can sometimes match experimentally measured and . This non-uniqueness can be broken by limiting the solution to the one for which < . Additionally, a three-parameter search is developed to simultaneously estimate the parameters , , and that fit the transition foam quality and apparent viscosity. However, a better strategy is to conduct and match a transient experiment in which 100% gas displaces surfactant solution at 100% water saturation. This transient foam quality scans the entire range of fractional flow and the values of the foam parameters that best match the experiment can be uniquely determined. Finally, a three-parameter fit using all experimental data of apparent viscosity versus foam quality is developed.
The numerical artifact of pressure oscillations in simulating this transient foam process is investigated by comparing finite difference algorithm with method of characteristics. Sensitivity analysis shows that the estimated foam parameters are very dependent on the parameters for the water and gas relative permeability. In particular, the water relative permeability exponent and connate water saturation are important.