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.
Prieto, C. A. (CEPSA Research Center) | Rodriguez, R. (CEPSA Research Center) | Romero, P. (CEPSA Research Center) | Blin, N. (CEPSA Research Center) | Panadero, A. (CEPSA Research Center) | Escudero, M. J. (CEPSA Research Center) | Barrio, I. (CEPSA Research Center) | Alvarez, E. (CEPSA Research Center) | Montes, J. (CEPSA EP) | Angulo, R. | Cubillos, H.
The design of an alkali-surfactant-polymer (ASP) formulation for chemical Enhanced Oil Recovery poses multiple challenges from the experimental point of view. The present research examines the laboratory procedures and experimental results aimed at selecting the most suitable chemicals for an ASP pilot trial at the Caracara Sur field (Los Llanos Basin, Colombia). The key challenge was the limited compatibility of the surfactant and polymer selected under reservoir conditions (temperature and total salinity), leading to phase separation of the ASP solution and losses of the activity of both chemicals. An extension of the experimental program was required to re-design the formulation and mitigate risks of damaging the formation in the following field trials. The formulation comprised an alkyl benzene sulfonate as main ingredient, a hydrolyzed polyacrylamide as viscosifying agent and some weak alkali to reach the optimum salinity of the mixture. A mono-alkyl diphenyl disulfonate ether was added as coupling agent to improve compatibility of the ASP mixture. The performance of the selected ASP formulation was assessed by means of interfacial tension measurements, long-term thermal stability tests and dynamic core-flooding tests. The formulation provided ultra-low interfacial tension (< 10-2 mN/m) and viscosity enough to assure an appropriate mobility control. Hence, the formulation was considered to be suitable for further testing in the field pilot.
Dwarakanath, Varadarajan (Chevron) | Dean, Robert M. (Chevron) | Slaughter, Will (Chevron) | Alexis, Dennis (Chevron) | Espinosa, David (Chevron) | Kim, Do Hoon (Chevron) | Lee, Vincent (Chevron) | Malik, Taimur (Chevron) | Winslow, Greg (Chevron) | Jackson, Adam C. (Chevron) | Thach, Sophany (Chevron)
Polymer flooding by liquid polymers is an attractive technology for rapid deployment in remote locations. Liquid polymers are typically oil external emulsions with included surfactant inversion packages to allow for rapid polymer hydration. During polymer injection, a small amount of oil is typically co-injected with the polymer. The accumulation of the emulsion oil near the wellbore during continuous polymer injection will reduce near wellbore permeability. The objective of this paper is to evaluate the long-term effect of liquid polymer use on polymer injectivity. We also present a method to remediate the near well damage induced by the emulsion oil using a remediation surfactant that selectively solubilizes and removes the near wellbore oil accumulation. We evaluated several liquid polymers using a combination of rheology measurement, filtration ratio testing and long-term injection coreflood experiments. The change in polymer injectivity was quantified in surrogate core after multiple pore volumes of liquid polymer injection. Promising polymers were further evaluated in both clean and oil-saturated cores. In addition, phase behavior experiments and corefloods were conducted to develop a surfactant solution to remediate the damage induced by oil accumulation. Permeability reduction due to long term liquid polymer injection was quantified in cores with varying permeabilities. The critical permeability where no damage was observed was identified for promising liquid polymers. A surfactant formulation tailored for one of the liquid polymers improved injectivity three- to five-fold and confirms our hypothesis of permeability reduction due to emulsion oil accumulation. Such information can be used to better select appropriate polymers for EOR in areas where powder polymer use may not be feasible.
The importance of tuning injection water chemistry for upstream is getting beyond formation damage control/water incompatibility to increase oil recovery from waterflooding and different improved oil recovery (IOR)/enhanced oil recovery (EOR) processes. The water chemistry requirements for IOR/EOR have been relatively addressed in the recent literature, but the key challenge for field implementation is to find an easy, practical, and optimum technology to tune water chemistry. The currently available technologies for tuning water chemistry are limited, and most of the existing ones are adopted from the desalination industry, which relies on membrane based separation. Even though these technologies yield a doable solution, they are not the optimum choice to alter injection water chemistry in terms of incorporating selective ions and providing effective water management for large scale applications. In this study, several of the current, emerging, and future desalination technologies are reviewed with an objective to develop potential water treatment solutions that can most efficiently alter injection water chemistry for SmartWater flooding in carbonate reservoirs.
Standard chemical precipitation technologies, such as lime/soda ash, alkali, and lime/aluminum based reagent, are only applicable for removing certain ions from seawater. The lime/aluminum based reagent process looks interesting, as it can remove both sulfates and hardness ions to provide some tuning flexibility for key ions included in the SmartWater. There are some new technologies under development that use chemical solvents to extract salt ions from seawater, but their capabilities to selectively remove specific ions need further investigation.
Forward osmosis and membrane distillation are the two emerging technologies, and these can provide good alternatives to reverse osmosis seawater desalination for the near-term. These technologies can offer a better cost-effective solution where there is availability of low grade waste heat or steam. The two new desalination technologies, based on dynamic vapor recovery and carrier gas extraction, are well suited to treat high salinity produced water for zero liquid discharge (ZLD). These technologies may not be able to provide an economical solution for seawater desalination. Carbon nanotube desalination, graphene sheet-based desalination, and capacitive deionization are the three potential future seawater desalination technologies identified for the long term. Among these, carbon nanotube based desalination is much attractive, although the technology is still largely under research and development.
This review study results show that there is no commercial technology yet available to selectively remove specific ions from seawater in one step and optimally meet desired water chemistry requirements of SmartWater flooding. As a result, different novel schemes involving selected combinations of chemical precipitation, conventional/emerging desalination, and produced water treatment technologies are proposed. These schemes represent both approximate and improved solutions to selectively incorporate specific key ions in the SmartWater, besides presenting the key opportunities to treat produced water/membrane rejects and provide ZLD capabilities in SmartWater flooding applications. The developed novel schemes can provide an attractive solution to capitalize on existing huge produced water resources in Saudi reservoirs to generate SmartWater and minimize wastewater disposal during field-wide implementation.
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.
Improved Oil Reocvery (IOR) technologies may offer a new strategy to improve the initial production (IP) and slow the production decline from oil-rich shale formations. Early implementation of chemical IOR technologies largely have been overlooked during strategic planning of unconventional reservoirs. The purpose of this study is to improve understanding of the dynamic processes of oil displacement by surfactants and to investigate mechanism of how surfactants extract oil. A successful conventional surfactant "huff-n-puff' treatment is described with a focus on any relationship between increased oil production and the surfactant soaking period. Surfactant chemistry has been considered as one of a few ultimate IOR solutions. Despite being well proven as effective chemicals to recover oil from convenetional reservoris, surfactants commonly are used in hydraulic fracturing of unconventional reservoris are just to promote flow back of the injected aqueous fluid over a relatively short time frame. In order to better understand the functionality of surfactants for obtaining favorable oil interaction with both the stimulation fluid and rock matrix, a specifically-designed "oil-on-a-plate" (OOAP) setup and procedure is employed to examine the penetration of surfactant into the oil-film that is adhereing to a solid surface. In addition to the well-recognized spontaneous imbibition and surface wettability alternation processes, surfactant also can gradually penetrate and mobilize oil droplets, resulting in improved oil recovert. If properly selected and designed, the surfactant additives in stimulation/fracturing fluids could have multi-functions towards improving both IP and the longer-term oil production. Besides serving as a demulsifier and flowback enhancer to boost IP, the surfactants could continuously lift-up and mobilize adsorbed oil to increase recoverable oil in place.
During an Alkaline-Surfactant-Polymer (
In this study, steady-state (
For brine/oil systems some dependence of apparent viscosity on rock permeability was observed; for systems with surfactants no such trend was noticable. The addition of surfactants substantially reduced the apparent viscosities; the viscosity reducing impact of surfactants could be balanced by the addition of polymer. Fractional flow analysis showed that the addition of surfactants reduces the impact of capillary forces resulting in straightened relative permeability curves and higher aqueous phase relative permeability end points.
It is anticipated that this study leads to a fast and fit for purpose characterization method of
The use of isenthalpic flash has become of interest for the simulation of some heavy oil recovery processes where large temperature changes are experienced. For these thermal simulations energy can be used as a primary variable. This leads to thousands or millions of individual multiphase isenthalpic flash calculations. Robust and efficient algorithms for multiple-phase isenthalpic flash are required to improve the efficiency of compositional simulations for thermal recovery.
The general framework on state function based flash specifications proposed by
Narrow boiling mixtures can be dealt with in the majority of cases without any significant difficulty. This is true of the direct substitution algorithm and the proposed solution procedure. The vast majority of examples can be solved without using Q function maximisation. The challenges associated with multiphase calculations in the Newton steps are investigated. In particular, inadequate initial estimate of the equilibrium type may lead to non-convergent iteration. This can usually be solved by introduction of a new phase and/or elimination of an existing phase. The speed of the method is analysed for a large number of specifications and is found to be only slightly more expensive than isothermal flash in the majority of cases.
Production from liquid-rich shale has become an important contributor to domestic production in the United States, but recovery factors are low. Enhanced Oil Recovery (EOR) methods require injectivity and interwell communication on reasonable time scales. We conduct a feasibility study for the application of recycled lean gas injection to displace reservoir fluids between zipper fracs in liquid-rich shales.
Using new analytical solutions to the Diffusivity equation for arbitrarily-oriented line sources/sinks plus superposition, we analyze the time for inter-fracture communication development, i.e. interference, and productivity index for both classical bi-wing fractures in a zipper configuration and complex fracture networks. We are able to map both pressure and pressure temporal derivative as a function of time and space for production and/or injection from parallel motherbores under the infinite conductivity wellbore and fracture assumption. The infinite conductivity assumption could be later relaxed for more general cases.
We couch the results in terms of geometrical spacing requirement for both horizontal wells and stimulation treatments to achieve reasonable time frames for inter-fracture communication and sweep for parameters typical of various shale plays. We further analyze whether spacing currently considered for primary production is sufficient for direct implementation of EOR or if current practice should be modified with EOR in the field development plan.
Polymer flooding is a proven technology to improve sweep efficiency, while being one of the most economical enhanced oil recovery (EOR) processes. Partially hydrolyzed polyacrylamide (HPAM) has been widely used for polymer flooding. As the HPAM usage for EOR increases, the challenge of produced water management is also raised because residual HPAM in produced water could increase total chemical oxygen demand and unwanted viscosity in discharging or re-injecting the water. As the environmental standards and regulations get more stringent, it is difficult for the conventional methods to meet the requirement for discharging. Use of magnetic nanoparticles (MNPs) to remove contaminants from produced water is a promising way to treat produced water in an environmentally green way with minimal use of chemicals. The main attraction for MNPs is their quick response to move in a desired direction with application of external magnetic field. Another attraction of MNPs is versatile and efficient surface modification through suitable polymer coating, depending on the characteristics of target contaminants. In this study, we investigate the feasibility of polymer removal using surface-modified MNPs and regeneration of spent MNPs for multiple re-use.
The electrostatic attraction between negatively charged HPAM polymer and positively charged MNPs controls the attachment of MNPs to HPAM molecular chain; and the subsequent aggregation of the now neutralized MNP-attached HPAM plays a critical role for accelerated and efficient magnetic separation.