Skauge, T. (CIPR Uni Research) | Skauge, A. (CIPR Uni Research) | Salmo, I. C. (CIPR Uni Research) | Ormehaug, P. A. (CIPR Uni Research) | Al-Azri, N. (PDO) | Wassing, L. M. (Shell Global Solutions International BV) | Glasbergen, G. (Shell Global Solutions International BV) | Van Wunnik, J. N. (Shell Global Solutions International BV) | Masalmeh, S. K. (Shell Global Solutions International BV)
Polymer injectivity is a critical parameter for implementation of polymer flood projects. An improved understanding of polymer injectivity is important in order to facilitate an increase in polymer EOR implementation. Typically, injectivity studies are performed using linear core floods. Here we demonstrate that polymer flow in radial and linear models may be significantly different and discuss the concept in theoretical and experimental terms.
Linear core floods using partially hydrolyzed polyacrylamides (HPAM) were performed at various rates to determine in-situ viscosity and polymer injectivity. Radial polymer floods were performed on Bentheimer discs (30 cm diameter, 2-3 cm thickness) with pressure taps distributed between a central injector and the perimeter production well. The in-situ rheological data are also compared to bulk rheology. The experimental set up allowed a detailed analysis of pressure changes from well injection to production line in the radial models and using internal pressure taps in linear cores.
Linear core floods show degradation of polymer at high flow rates and a severe degree of shear thickening leading to presumably high injection pressures. This is in agreement with current literature. However, the radial injectivity experiments show a significant reduction in differential pressure compared to the linear core floods. Onset of shear thickening occurs at significantly higher flow velocities than for linear core floods. These data confirm that polymer flow is significantly different in linear and radial flow. This is partly explained by the fact that linear floods are being performed at steady state conditions, while radial injections go through transient (unsteady state) and semi-transient pressure regimes.
History matching of polymer injectivity was performed for radial injection experiments. Differences in polymer injectivity are discussed in the framework of theoretical and experimental considerations. The results may have impact on evaluation of polymer flood projects as polymer injectivity is a key risk factor for implementation.
Luo, Haishan (The University of Texas at Austin) | Mohanty, Kishore K. (The University of Texas at Austin) | Delshad, Mojdeh (The University of Texas at Austin) | Pope, Gary A. (The University of Texas at Austin)
Upscaling of unstable immiscible flow remains an unsolved challenge for the oil industry. The absence of a reliable upscaling approach greatly hinders the effective reservoir simulation and optimization of heavy oil recoveries using waterflood, polymer flood and other chemical floods, which are inherently unstable processes. The difficulty in upscaling unstable flow lies in estimating the propagation of fingers smaller than the gridblock size. Using classical relative permeabilities obtained from stable flow analysis can lead to incorrect oil recovery and pressure drop in reservoir simulations.
In a recent study based on abundant experimental data, it is found that the heavy-oil recovery by waterfloods and polymer floods has a power-law correlation with a dimensionless number (named viscous finger number in this paper), which is a combination of viscosity ratio, capillary number, permeability, and the cross-section area of the core. Based upon this important finding as well as the features of unstable immiscible floods, an effective-finger model is developed in this paper. A porous medium domain is dynamically identified as three effective zones, which are two-phase flow zone, oil single-phase flow zone, and bypassed oil (isolated oil island) zone, respectively. Flow functions are derived according to effective flows in these zones. This new model is capable of history-matching a set of heavy-oil waterflood corefloods under different viscosity ratios and injection rates. Model parameters obtained from the history match also have a power-law correlation with the viscous finger number.
The build-up of this correlation contains reasonable physical meanings to quantitatively characterize the upscaled behavior of viscous fingering effects. Having such a correlation enables the estimation of model parameters in any gridblock of the reservoir by knowing the local viscous finger number in reservoir simulations. The model is applied to several heavy-oil field cases with waterfloods and polymer floods with different heterogeneities. Oil recovery in water flooding of viscous oils is overpredicted by classical simulation methods which do not incorporate viscous fingering properly. Simulation results indicate that the new model reasonably differentiates the oil recoveries at different viscous finger numbers, e.g., lower injection rate leads to higher oil recovery. In contrast, classical simulations obtain close oil recoveries under different injection rates or degrees of polymer shear-thinning, which is apparently incorrect for unstable floods. Moreover, coarse-grid simulations using the new model are able to obtain consistent saturation and pressure maps with fine-grid simulations when the correlation lengths are not smaller than the coarse gridblock size. Furthermore, it is well captured by the model that the shear-shinning polymer solution can strengthen the fingering in high-permeability regions due to increased capillary number and viscosity ratio, which is not observed in waterflood. As a whole, the new model shows encouraging capability to simulate unstable water and polymer floods in heavy oil reservoirs, and hence can facilitate the optimization of heavy-oil EOR projects.
Wang, D. (University of North Dakota) | Dawson, M. (Statoil Gulf Services LLC) | Butler, R. (University of North Dakota) | Li, H. (Statoil Gulf Services LLC) | Zhang, J. (University of North Dakota) | Olatunji, K. (University of North Dakota)
With the recent dramatic drop in oil price, production from ultra-tight resources, like the Bakken formation, may drop substantially. Since expenditures for drilling, completion, and fracking have already been made, existing wells will continue to flow, but oil rates will decline—rapidly in many cases. In a low oil-price environment, what can be done to sustain oil production from these tight formations?
We are testing a surfactant imbibition process to recovery oil from shales. We measured surfactant imbibition rates and oil recovery values in laboratory cores from the Bakken shale. After optimizing surfactant formulations at reservoir conditions, we observed oil recovery values up to 10–20% OOIP incremental over brine imbibition. However, whether or not surfactant imbibition will be a viable recovery process depends on achieving sufficiently high oil production rates in a field setting—which requires that we identify conditions that will maximize imbibition rate, as well as total oil recovery. In this paper, we describe laboratory evaluations of oil recovery using different core plugs. These recovery studies involved
(1) surfactant formulation optimization on concentration, salinity and pH, (2) characterization of phase behavior, (3) spontaneous imbibition, and (4) forced imbibition (flooding) with gravity drainage assistance.
In preserved cores, we observed: (1) Formulations using 0.1% surfactant concentration at 4% TDS salinity showed favorable oil recoveries (up to 40% OOIP). (2) Generally, surfactant formulations at optimal concentration and salinity were stable at high temperature (115°C). (3) Injectivity/permeability enhancements up to 75 percent occurred after acidification using acetic acid or HCl. (4) Wettability alteration is the dominant mechanism for surfactant imbibition. Of course, actions that increase fracture width will aid gravity drainage and oil recovery. This information is being used to design and implement a field application of the surfactant imbibition process in an ultra-tight resource.
In the case of surfactant EOR, an optimum formulation of surfactant has to be injected in the reservoir. This so-called optimum formulation corresponds to a minimum in the interfacial tension and a maximum in oil recovery and may be obtained with an appropriate balance of the hydrophobic and hydrophilic affinities of the surfactant. Salinity—scan tests are generally used to screen phase behavior of surfactant formulations before conducting time-consuming coreflood tests. The objective of this study was to develop a high-throughput dynamic microfluidic tensiometer, with the aim of studying interfacial phenomena between EOR injected formulations and crude oils and of optimizing chemical EOR processes for pilot or field applications.
We have selected a method based on the Rayleigh-Plateau instability and the analysis of the droplets to jetting transition in a coaxial flow of two fluids. In fact, in coaxial flows, the transition between a droplet and a jetting regime depends on the velocities of each phase, the viscosity ratio, the confinement and the interfacial tension (IFT). As the three first parameters are known, the dynamic interfacial tension can be calculated. This microfluidic device has been specifically designed to support high temperatures (up to 150°C), high pressures (up to 150 bars) and is compatible with complex fluids such as crude oils and solutions of surfactants and polymers.
The method was first developed and validated on a microfluidic device on model fluids at ambient temperature and atmospheric pressure for IFTs higher than 1 mN/m. It was then successfully applied for the measurement of IFTs over more than four decades. Measurements were also performed with a crude oil and a typical surfactant formulation. The validation of the HP/HT assembly, which has been designed with the aim to work in reservoir conditions, is currently under progress. By using this tensiometer, it would be quite easy to perform in short time numerous salinity scans on real systems in order to get the evolution of IFT and determine the optimal salinity S*.
Polymer transport and preparation can present a key challenge in chemical EOR project implementation.
Hydrolyzed polyacrylamide in emulsion form presents some advantages, including an easier transportation and a simplification of the injection process. The trade off is a lower active concentration (~30% - 50%), which increases the volumes to be transported, as well as the presence of oil and emulsifiers, which may have unintended effects in the reservoir.
In this article, we compare two industrial and commercially-available polymers, one in powder form from the gel process, and the other in an inverse emulsion, with similar viscosifying power.
Properties of both polymers are investigated through rheological and screen factor measurements, filterability tests on bulk solutions, shear thickening behavior and resistance to shear degradation in porous medium. The likely origin of the observed differences is discussed in light of the two polymerization methods (bulk vs. emulsion) that lead to differences in polydispersity. Mobility reduction and residual resistance factor measurements during propagation tests at low velocity give some insight on the propagation of the stabilized oil droplets coming from the injected emulsion. Finally, oil recovery efficiency is investigated through secondary polymer injections on sandpacks. No significant difference was observed between the polymers in term of oil recovery or pressure behavior.
These results are relevant to oil companies planning polymer or surfactant-polymer pilots and considering the tradeoffs between emulsion and powder polymers.
Alexis, Dennis (Chevron Energy Technology Company) | Varadarajan, Dwarakanath (Chevron Energy Technology Company) | Kim, Do Hoon (Chevron Energy Technology Company) | Winslow, Greg (Chevron Energy Technology Company) | Malik, Taimur (Chevron Energy Technology Company)
Performance of current synthetic EOR polymers is primarily constrained by salinity, temperature and shear which restrict their application to low to moderate salinity, low to moderate temperature and relatively high permeability reservoirs. The primary goal of the current work is to qualify recently developed associative polymers (AP) for EOR applications as well as to study their behavior in porous media. We also compare their performance with conventional non-associative polymers. In this work, we present the evaluation of several associative polymers. Two broad types of associative polymers were tested, one with a partially hydrolyzed poly acrylamide (HPAM) backbone and the other with a sulfonated HPAM backbone. The concentrations of the tested polymer vary between 75 ppm and 1000 ppm. We demonstrate the applicability of these innovative AP's through the carefully controlled lab experiments: (1) Corefloods in sandpacks to compare the sweep behaviors with conventional HPAM's. (2) Single phase flooding experiments are carried out in consolidated outcrop rocks to identify optimal polymer concentrations to achieve the desired in-situ resistance. (3) One dimensional displacement experiments with 8 cP and 90 cP oil are carried out in both unconsolidated and consolidated rocks at different temperatures to validate improved oil recovery. Results generally indicate that associative polymers require lower polymer concentration to generate high resistance factors in porous media and have stable long term injectivity behavior in high permeability rocks (>1D). Associative polymers with HPAM backbone have better filterability and injectivity in comparison to those with HPAM sulfonated backbone in low permeability(<300mD) rocks. Improved oil recovery in high permeability rocks compare well with conventional HPAM and sulfonated HPAM polymers. Based on the laboratory results, we are able to establish the selection baseline for associative polymers in different permeability rocks, salinities and temperatures. Such information can be used to select and screen the appropriate associative polymers, resulting in extending their applicability envelope in EOR.
When compared with steam-assisted gravity drainage (SAGD) operations in the McMurray Formation, Athabasca Oil Sands, SAGD projects in the Clearwater Formation at Cold Lake did not perform as expected, likely because of reservoir properties. This paper will use the Orion SAGD case study to: (1) investigate the impacts of reservoir properties on the SAGD thermal efficiency by field evidences; (2) identify key geological parameters influencing each well pad; and (3) summarize major geological challenges for Orion SAGD expansion.
Wireline log data were interpreted to characterize reservoir properties, which were used to build 3D models. 3D visualizations and 2D cross sections of the reservoir revealed spatial distribution and heterogeneity of each property. SAGD production performance was analyzed using: (1) temperature profiles that monitored the growth of the steam chamber; (2) cumulative steam-oil ratios (CSORs); and (3) oil production rates (OPRates), which are direct indicators of thermal efficiency.
Results show that impermeable barriers and low-permeability zones were detrimental to steam injectivity and steam chamber growth, as observation wells in Pilot Pads 1 and 3 did not detect any steam saturation. High-permeability zones favored high steam injectivity and mobility, especially in Pad 105. Steam chambers were irregularly shaped by high shale-content zones, as two sharp spikes displayed on the temperature profile in Pad 103. Low oil-saturation zones and thin net-pays increased the CSORs, as seen in Pads 106 and 104. Impermeable barriers are almost horizontal, making no difference on well pad orientation by their dip angles. Lack of porosity variation made it difficult to identify the impact of porosity on each well pad.
The relatively extensive distribution of impermeable barriers between and above well pairs, as well as the relatively large area of low oil saturation and thin net-pay, were identified as major geological challenges.
Chen, Zhao (New Mexico Inst-Mining & Tech) | Du, Cheng (New Mexico Inst-Mining & Tech) | Kurnia, Ivan (New Mexico Inst-Mining & Tech) | Lou, Junjie (New Mexico Inst-Mining & Tech) | Zhang, Guoyin (New Mexico Petroleum Recovery Research Center) | Yu, Jianjia (New Mexico Petroleum Recovery Research Center) | Lee, Robert L. (New Mexico Petroleum Recovery Research Center)
Hydrodynamic retention is one of the contributors to polymer loss in porous media. In this study, effects of flow rate, polymer molecular weight, and core permeability on hydrodynamic retention were investigated. To quantify hydrodynamic retention, injection of two identical polymer banks at different rates separated by 100 pore volumes of brine flushing was performed. Three HPAM polymers with molecular weights of 6–8 million, 12 million, and 20 million Daltons were tested in a 135 mD sandstone core and xanthan polymer with molecular weight of 2–2.5 million Daltons was tested in an 87 mD sandstone core. The retention of 6–8 million Daltons HPAM in a 1,650 mD sandstone core was also measured. Polymer retention in a fresh core was first measured at low injection rate of 3.11 ft/day. Then, 100 PV of 2% NaCl brine was injected to displace all the mobile polymer molecules in the core till pressure drop across the core became stable. Hydrodynamic retention at elevated flow rates was determined after the completion of retention at lower rates and comparisons with the initial polymer retention were made.
Retention of 96.1 µg/g in the 135 mD core was detected for the 6–8 million HPAM at a flow rate of 3.11 ft/day. Increase of flow rate from 3.11 ft/day to 6.22 ft/day and 12.4 ft/day resulted in incremental retention of 2.27 µg/g and 5.38 µg/g, respectively. The injection of a higher molecular weight polymer at the same rate was performed after retention was satisfied with a lower molecular weight polymer. It was found the degree of hydrodynamic retention was greater when higher molecular weight polymers were injected. When core permeability was changed from 135 mD to 1,650 mD, both the initial and hydrodynamic retention were dramatically decreased. The initial retention of xanthan was 66.7 µg/g in an 87 mD sandstone core, which was smaller compared to the retention of HPAM in the similar core. However, hydrodynamic retention measurements of xanthan gives 3.26 µg/g and 6.38 µg/g increments with the increase of flow rate from 3.11 ft/day to 6.22 ft/day and 12.4 ft/day, which suggested that the retention of xanthan is slightly more sensitive to the change of injection rate than HPAM. This study also implied that measurement of residual resistance factor after polymer injection should be completed after sufficient brine flushing (around 100 PV), otherwise, an overestimated residual resistance factor might be provided.
Jong, Stephen (University of Texas at Austin) | Nguyen, Nhut M. (University of Texas at Austin) | Eberle, Calvin M. (University of Texas at Austin) | Nghiem, Long X. (Computer Modelling Group Ltd.) | Nguyen, Quoc P. (University of Texas at Austin)
Low Tension Gas (LTG) flooding is a novel EOR process which can address challenging reservoir conditions such as high salinity, high temperature, and tight rock. Current process understanding is limited, and a joint experimental and modeling approach allows for both interpretation and insight into the complex interactions between the key process parameters of salinity gradient, foam strength, microemulsion phase behavior, and phase desaturation in order to achieve a physically correct and predictive process model.
We performed a series of corefloods in high permeability Berea sandstones (~500 mD) to demonstrate the impact of salinity gradient on the LTG process and interactions between key mechanisms such as microemulsion phase behavior and foam stability. In order to provide additional insight into the experimental study and improve understanding of the LTG process, we used our newly developed LTG simulator which we built within CMG GEM.
The results demonstrate that decreasing slug injection salinity can lead to a 15% increase in residual oil in place (ROIP) recovery over a slug injected at optimum salinity, with earlier breakthrough and steeper recovery slope. In addition, there is evidence of a late time pressure buildup as salinity is decreased through mixing with drive salinity which is indicative of increasing foam stability. This may be due to an inverse relationship between oil-water IFT and foam stability and thus designing an optimal salinity gradient for an LTG process requires balancing oil mobilization due to ultralow IFT and effectively displacing mobilized oil with adequate foam mobility control.
We introduce and show the strength our compositional LTG simulator in a pioneering laboratory and simulation study that sheds light on the interaction between salinity, microemulsion phase behavior, and foam strength. Our conclusions indicate a significant departure from traditional ASP understanding and methodology when designing an LTG salinity gradient and serve as a foundation for future investigation.
Water-based polymers are often used to improve oil recovery by increasing displacement sweep efficiency. However, recent laboratory and field work has suggested these polymers, which are often viscoelastic, may also reduce residual oil saturation. The objective of this work is to investigate the effect of viscoelastic polymers on residual oil saturation in Bentheimer sandstones and identify conditions and mechanisms for the improved recovery. Bentheimer sandstones were saturated with a heavy oil (120cp) and then waterflooded to residual oil saturation using brine followed by an inelastic Newtonian fluid (diluted glycerin). These floods were followed by injection of a viscoelastic polymer, hydrolyzed polyacrylamide (HPAM).
Significant reduction in residual oil was observed for all core floods performed at constant pressure drop when the polymer had significant elasticity (determined by the dimensionless Deborah number,