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.
Achieving maximum oil recovery utilizing CO2 has limitations when operating at, or very close, to the Minimum Miscibility Pressure (MMP) of the CO2 in the oil. A modular source of CO2 would allow Enhanced Oil Recovery (EOR) flooding of "stranded" and shallow reservoirs. Unfortunately, modular sources of CO2 production often include CO and N2 mixed with the CO2. Thus, testing for EOR application of a mixed gas-containing CO2, N2, and CO was initiated.
Bench scale testing using Rising Bubble Apparatus (RBA), Slim Tubes, and linear core flood have been conducted on oils ranging from 16-42° gravities having viscosities of 0.5-280 cp. All tests were conducted at reservoir temperatures and pressures. CO, being a strong reducing agent, was further tested on reservoir rock containing swelling clays with hydrated ferric hydroxides. Due to the apparent reduction of the ferric hydroxide, and the liberation of its water of hydration, an increase in matrix permeability and clay stabilization, was observed.
For most oils tested, the CO2/CO mixture increased rate of oil recovery by 2-3X, using only 50-60% as much gas/bo as compared to pure CO2. Recovery factors of 80%, at immiscible pressures 30-40% below CO2 MMP, were achieved. Addition of 15% N2 (v/v) to the CO2/CO mixture did not impair oil recovery. Interfacial testing (IFT) of oils, using pure CO, demonstrated a lowering of the IFT. RBA testing of asphaltine-rich heavy oils has shown that a mixture of CO2/CO dissolves into the oil at a far faster rate than either CO2 or CO individually and faster than the sum of both individual gases. A similar test using non-asphaltine type oils did not display this unique characteristic. Slim tube testing suggests that CO facilitates the mobilization of asphaltine-rich heavy oils and lowers viscosity. A linear corefloods of a reservoir containing 5% smectite + illite/smectite + and chlorite demonstrated a 275% increase in matrix permeability. Packed column tests, containing quartz sand and bentonite, demonstrated up to 300-900% increase in permeability in the presence of CO.
Thus a method to recover oil faster, from stranded reservoirs, at pressures below MMP, using significantly less gas, appears possible. In addition the use of CO, either alone or in combination with CO2 and/or N2, has been shown to increase matrix permeability. Such a gas mixture may be beneficial to achieving low pressure EOR from shallow, "stranded" reservoirs, non-conventional shale oil reservoirs, and viscous, heavy oil reservoirs at low temperatures. Incorporation of CO, or CO2/CO, in a frac fluid, or alternately as a post frac cleanup for shale oil and gas applications appears to warrant investigation.
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.
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
A physically based generic viscosity model for synthetic polymer solutions has been created. It gives viscosities as a function of shear rates (Carreau curves). The input to the model is concentration, temperature, salinity and molecular weight (polymer type). A model for mechanical degradation of synthetic polymer solutions has also been developed. It calculates the solution viscosity after mechanical degradation by flow through a porous medium. The two models are linked through molecular weight distributions of the polymer solutions.
The viscosity model fits very well experimental data from viscometry. The mechanical degradation model also fits available experimental data when utilising a correction factor. The models have good predictive power and can be used for different purposes such as, estimating mechanical degradation for different plugging scenarios calculating the added polymer concentration needed to achieve a given in-situ viscosity at a certain level of degradation calculating the viscosity degradation for a diluted production fluid with known Mw (from analysis) and unknown concentration. estimating degradation during operation of a well based on the pressure data choosing the best polymer solution for a specific field calculating the effects of pre-shearing (before injection) and the optimal degree of pre-shearing perform case studies to investigate the impact of system parameters on polymer degradation
estimating mechanical degradation for different plugging scenarios
calculating the added polymer concentration needed to achieve a given in-situ viscosity at a certain level of degradation
calculating the viscosity degradation for a diluted production fluid with known Mw (from analysis) and unknown concentration.
estimating degradation during operation of a well based on the pressure data
choosing the best polymer solution for a specific field
calculating the effects of pre-shearing (before injection) and the optimal degree of pre-shearing
perform case studies to investigate the impact of system parameters on polymer degradation
The models have also been used for further development to estimate polymer injectivity as well as degradation in process equipment.
Currently, the model predicts slightly increasing degradation for decreasing water salinity which is opposite the trend indicated by most experimental data. Reasons for the deviation are disussed together with suggestions for possible extention of the model.
Mukherjee, Joydeep (The Dow Chemical Company) | Nguyen, Quoc P. (The University of Texas at Austin) | Scherlin, John (Fleurde Lis Energy) | Vanderwal, Paul (The Dow Chemical Company) | Rozowski, Peter (The Dow Chemical Company)
A supercritical CO2 foam pilot, comprised of a central injection well in an inverted 5-spot pattern, was implemented in September 2013 in Salt Creek field, Natrona County WY. In this paper we present a thorough analysis of the pilot performance data that has been collected to date from the field. A monitoring plan was developed to analyze the performance of the pilot area wells before and after the start of the foam pilot. The injection well tubing head pressure was controlled to maintain a constant bottom hole pressure and the fluid injection rates were monitored to capture the effect of foam generation on injectivity. Inter-well tracer studies were performed to analyze the change in CO2 flow patterns in the reservoir. Production response was monitored by performing frequent well tests. The CO2 injection rate profile monitored over several WAG cycles during the course of the implementation clearly indicates the formation and propagation of foam deep into the reservoir. CO2 soluble tracer studies performed before and after the start of the foam pilot indicate significant areal diversion of CO2. The production characteristics of the four producing wells in the pilot area indicate significant mobilization of reservoir fluids attributable to CO2 diversion in the pattern. The produced gas-liquid ratio has decreased in all four of the producing wells in the pattern. Analysis of the oil production rates shows a favorable slope change with respect to pore volumes of CO2 injected. Segregation of CO2 and water close to the injection well seems to be the primary factor adversely affecting CO2 sweep efficiency in the pilot area. Foam generation leads to a gradual expansion of the gas override zone. The gradual expansion of the gas override zone seems to be the principal mechanism behind the production responses observed from the pilot area wells.
Pilots are widely used for the purpose of gathering valuable information about performance and practical challenges of implementing a particular CEOR process in a given field (
Addition of chemical species to the material balance equations alongside finer resolution requirements for CEOR simulations compared to waterfloods (WF), often make it impractical to run full field CEOR simulations to the required accuracy. Massively parallel computing, dynamic local grid refinement and sector modeling have been used with varying success, of which sector modeling is the most common. Sector models, by their very definition, are also naturally suited for modeling of pilots.
The art of sector modeling needs mastering a few important steps such as: appropriate selection of the sector model extent, details on carving it out of the Full Field Model (FFM), populating it with proper petrophysical and fluid properties, initializing it to correct initial conditions and optimizing its boundary conditions. On top of that, choice of optimum grid size for proper trade-off of simulation run times and accuracy needs to be considered.
This paper presents a case study for appropriate simulation of a CEOR pilot within Chevron. The candidate has a waterflood history matched FFM. This model is used to generate a sector model for the CEOR pilot area. This paper outlines how the extent of the sector model and all the regions in communication with the Area of Interest (AOI) is decided. It also discusses proper initialization and optimization of the boundary conditions of the sector model along with its appropriate refinement and grid optimization. Proper CEOR simulations on the final optimized sector model and sensitivity analysis are also presented. The challenges, lessons learned and best practices are shared and important considerations for adequate simulation of CEOR processes are outlined.
This paper describes the analysis and positive results of injecting water, from constant to discontinuous rates in a reservoir under a high water cut stage. By following and improving waterflooding surveillance applications it was possible not only to describe the kind of reservoir, but also to keep the water cut up for a longer time. The goal of this study is to demonstrate the powerful benefits of applying and improving the surveillance plots that are available in the existing literature. The pore volumes injected plot, which was enhanced in this study by adding the injection rates per well in a secondary Y axis, was a powerful tool to identify the water cut behavior.
One of the two injector wells of the field was shut in for about 5 months and returned to its water injection conditions for 7 months. These events are presented in three phases. The first is related to the reservoir characterization achieved before the injector shut in. The second includes the well responses observed and monitored during the injector shut in. And, the third illustrates the promising reservoir results after the injector shut in. As well, an economic model is also developed.
As a result of the field events, analysis, and results described in this paper, the reservoir water cut was stable for a longer time in comparison with the whole life of the IOR project. In addition the increase Estimate Ultimate Recovery was 304,968 bbl for 8 years, the net present value of the field increased to 24%, and the average operating cost was reduced to 2.49 USD/bbl from 2015 to 2022.
The cyclic waterflooding existing literature supports reservoir characterization, analysis and results achieved in Tiguino Field. The initial application monitored in Ecuador will be helpful to be considered as a first approach for starting an IOR optimization in similar stratified reservoirs. The results obtained in Tiguino field are helpful not only as a real example but also as a statistical support for cyclic waterflooding. The Tiguino case experience would be extrapolated to other fields worldwide.
Mishra, Ashok (Conoco Phillips) | Abbas, Sayeed (Conoco Phillips) | Braden, John (Conoco Phillips) | Hazen, Mike (Conoco Phillips) | Li, Gaoming (Conoco Phillips) | Peirce, John (Conoco Phillips) | Smith, David D. (Conoco Phillips) | Lantz, Michael (TIORCO, a Nalco Champion Company)
This paper is a field case review of the process and methodologies used to identify, characterize, design, and execute a solution for a waterflood conformance problem in the Kuparuk River Unit in late 2013. In addition, post treatment analysis in a complex WAG flood will be discussed. The Kuparuk River Field is a highly fractured and faulted, multi-layer sandstone reservoir located on the North Slope of Alaska. Large scale water injection in the field was initiated in 1981 and overall the field responded favorably to waterflood operations. In 1996, Kuparuk implemented a miscible WAG flood in many areas of the field. However, natural fault and fracture connectivity has resulted in some significant conformance issues between high angle wells in the periphery. Methodologies employed to identify and characterize one specific conformance issue will be outlined. Details of diagnostic efforts, and how they were used to identify, characterize and mitigate an injector/producer interaction through a void space conduit will be discussed. The solution selected to resolve this conformance issue involved pumping a large crosslinked hydrolyzed polyacrylamide (HPAM) gel system. The solution used a tapered concentration design with one of the highest molecular weight HPAM polymers available. Before execution of this solution, extensive history matching and modeling of the solution design and benefits were used to justify this effort. These modeling efforts and their projections will be reviewed. This solution was pumped into the offending injector in late 2013, and offset producers were carefully monitored for gel breakthrough. The polymer treatment design parameters, including rates and pressure limits were used to generate an effective solution. A discussion of this active design approach, a complete review of the well problem dynamics, treatment operations, products used, and potential complications associated with these products will be discussed. Post solution execution performance analysis was difficult due to the active nature of this MWAG flood. A variety of plotting and analysis techniques were used to identify and quantify the results. A discussion of these results will be provided. Finally, a summary of lessons learned, and a limited discussion of future plans will be presented.
Lotfollahi, Mohammad (The University of Texas at Austin) | Kim, Ijung (The University of Texas at Austin) | Beygi, Mohammad R. (The University of Texas at Austin) | Worthen, Andrew J. (The University of Texas at Austin) | Huh, Chun (The University of Texas at Austin) | Johnston, Keith P. (The University of Texas at Austin) | Wheeler, Mary F. (The University of Texas at Austin) | DiCarlo, David A. (The University of Texas at Austin)
The use of foam in gas enhanced oil recovery (EOR) processes has the potential to improve oil recovery by reducing gas mobility. Nanoparticles are a promising alternative to surfactants in creating foam in the harsh environments found in many oil fields. We conducted several CO2-in-brine foam generation experiments in Boise sandstones with surface-treated silica nanoparticle in high-salinity conditions. All the experiments were conducted at the fixed CO2 volume fraction (g = 0.75) and fixed flow rate which changed in steps. We started at low flow rates, increased to a medium flow rates followed by decreasing and then increasing into high flow rates. The steady-state foam apparent viscosity was measured as a function of injection velocity.
The foam flowing through the cores showed higher foam generation and consequently higher apparent viscosity as the flow rate increased from low to medium and high velocities. At very high velocities, once foam bubbles were finely textured, the foam apparent viscosity was governed by foam shear-thinning rheology rather than foam creation. A noticeable "hysteresis" occurred when the flow velocity was initially increased and then decreased, implying multiple (coarse and strong) foam states at the same superficial velocity.
A normalized generation function was combined with CMG-STARS foam model to cover the full spectrum of foam flow behavior observed during the experiments. The new foam model successfully captures foam generation and hysteresis trends observed in presented experiments in this study and other foam generation experiments at different operational conditions (e.g. fixed pressure drop at fixed foam quality, and fixed pressure drop at fixed water velocity) from the literature.
The results indicate once foam is generated in porous media, it is possible to maintain strong foam at low injection rates. This makes foam more feasible in field applications where foam generation is limited by high injection rates (or high pressure gradient) that may only exist near the injection well. Therefore, understanding of foam generation, and foam hysteresis in porous media and accurate modeling of the process are necessary steps for efficient foam design in field.