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Collaborating Authors
Oil & Gas
Polymer Stabilized Foam Rheology and Stability for Unconventional EOR Application
Griffith, Christopher (Chevron) | Jin, Julia (Chevron) | Linnemeyer, Harry (Chevron) | Pinnawala, Gayani (Chevron) | Aminzadeh, Behdad (Chevron) | Lau, Samuel (Chevron) | Kim, Do Hoon (Chevron) | Alexis, Dennis (Chevron) | Malik, Taimur (Chevron) | Dwarakanath, Varadarajan (Chevron)
Abstract It has been shownthat injecting surfactants into unconventional hydraulically fractured wells can improve oil recovery. It is hypothesized that oil recovery can be further improved by more efficiently distributing surfactants into the reservoir using foam. The challenge is that in high temperature applications (e.g., 240 F) many of these formulations may not make stable foams as they have only moderate foaming properties (short half-life). Therefore, we are evaluating polymers that can be used to improve foam stability in high temperature wells which has the potential to improve oil recovery beyond surfactant only injection.Surfactant stabilized nitrogen foams were evaluated using a foam rheometer at pressures and temperatures representative of a field pilot well. The evaluation process consisted of measuring baseline properties (foam viscosity and stability) of a surfactant stabilized foam without any added stabilizer. Next, conventional enhanced oil recovery polymers (HPAMs, modified-HPAMs, and nonionic polymers) were added at different concentrations to determine their impacts on foam stability. Our results demonstrate that inclusion of a relatively low concentration (0.05 wt% – 0.2 wt%) of polymer has a pronounced impact on foam stability. It was determined that reservoir temperature plays a key role in selecting astabilizing polymer. For example, at higher temperatures (>240 F), sulfonated HPAM polymers at just 0.2 wt% more than doubled the stability of the foam. The polymer that was selected from this lab work was tested in a foam field trial in an unconventional well. It is thought that improved foam stability could potentially help improve the distribution of surfactants in fracture network and further improve oil recovery.
- North America > United States > Texas > Fort Worth Basin > Barnett Shale Formation (0.99)
- North America > United States > South Dakota > Williston Basin > Bakken Shale Formation (0.99)
- North America > United States > North Dakota > Williston Basin > Bakken Shale Formation (0.99)
- North America > United States > Montana > Williston Basin > Bakken Shale Formation (0.99)
Recent Advances of Alkali-Surfactant-Polymer ASP Flooding in China
Guo, Hu (China University of Petroleum-Beijing) | Zhang, Menghao (China University of Petroleum-Beijing) | Lyu, Xiuqin (Sinopec Northwest Oil Field Company) | Xu, Yang (China National Logging Company Ltd) | Meng, En (China University of Petroleum-Beijing) | Fu, Hongtao (China University of Petroleum-Beijing) | Zhang, Yuxuan (China University of Petroleum-Beijing) | Song, Kaoping (China University of Petroleum-Beijing)
Abstract Latest advances of ASP flooding (ASP) field tests in China are provided to focus ontwo major concerns: ASP EOR cost and technical matureness. Benefits with and without alkali for ASP were discussed. ASP flooding mechanisms in Chinese perspective are discussed. Although 54 tests were surveyed, 5 recent typical ASP field tests are discussed with special attention: the only one using horizontal wells (HASP), one combining microbial flooding (MASP), one in conglomerate reservoir (Xinjiang), one in a 81°C reservoir (Henan) and the only organic alkali one (OASP). 2D nanosheets surfactant with moderate low interfacial tension (IFT)(10-1mN/m) making highest incremental oil recovery (IOR) (Yin et al, 2019; Raj et al,2019) proves that ultra-low IFT is not essential for EOR (Figure 1). It is emulsification rather than ultra-low IFT that dominates high IOR (Guo, 2018; Cheng et al, 2019). Alkali is very important and necessary to reduce surfactant adsorption, promote emulsification and improve polymer injectivity (Figure 2). Interfacial viscosity should have been regarded more important. 29 commercial blocks in Daqing are conducted (Cheng etal,2019). ASP flooding produced 32.6 million bbl oil (Zhang, 2019) in 2018 and accounts for 14% total oil production (Figure 3). HASP test (2012-2017) in Daqing makes the highest IOR of 29.66% OOIP, 10%higher than all the other vertical well ASP (VASP). 5 horizontal wells (3 Injectors 2 Producers). ASP slug is 0.45PV and viscosity is 30 mPa.s with 10-3 mN/m IFT.14. 1millon bbl oil is produced. OASP field test with 10 injectors and 21 producers in high divalent ion heavy oil reservoir in Shengli produced 6.47 millionbbls and predicted IOR of 11.9% OOIP with 0.45PV slug (0.1%A +0.3%S+1500ppm P). Water cut dropped from 97.8% to 90.5% and daily oil production rises from 138.6 bbl to 554.4bbl. B1DD and B2XASP reported financial internal rate of return (FIRR) of 18.01% and 22.7% respectively. MASP (2008-2014) was reported IOR of 20.57% OOIP (26.7% predicted). 1.237 PV chemical slug including 0.06PV microbialslug [2% microbe fluid and 2% nutrient solution] was injected to 9 Injectors corresponding to 16 Producers. Better injectivity and economic performance are observed (FIRR=31.40%). Chemical cost is445 CNY/ton. ASPF in a conglomerate reservoir goes well. ASP flooding was commercially used in Daqing. Some commercial ASPtests failed to attain its goal (Cheng et al,2019). HASP has achieved 10% OOIP higher incremental oil recovery than all the others VASP. Ultra-low IFT should not be the most important factor aspreviously believed. Emulsification contributed by alkali is vital. However, emulsion viscosity should beoptimized. A totally different new macroscopic capillary number theory can well explain many hard-to-understand field test results. Alkali is both important and necessary.
Abstract Effective oil displacement from a reservoir requires adequate and properly directed pressure gradients in areas of high oil saturation. If the polymer bank is too large or too viscous during a polymer flood, the pressure drop from the injection well to the polymer front may act as a pressure barrier by usurping most of the downstream driving force for oil displacement. Polymer injection pressures must be limited. The maximum allowable injection pressure is commonly constrained by caprock integrity, injection equipment, and/or regulations, even though fractures can be beneficial to polymer injectivity (and even sweep efficiency in some cases). This paper examines when the pressure-barrier concept limits the size and viscosity of the polymer bank during a polymer flood. Both analytical and numerical methods are used to address this issue. We examine the relevance of the pressure barrier concept for a wide variety of circumstances, including oil viscosities ranging from 10-cp (like at Daqing, China) to 1650-cp (like at Pelican Lake, Alberta), vertical wells (like at Tambaredjo, Suriname) versus horizontal wells (like at Milne Point, Alaska), single versus multiple layered reservoirs, permeability contrast, and with versus with crossflow between layers. We also examine the relation between the pressure-barrier concept and fractures and fracture extension during polymer injection. We demonstrate that in reservoirs with single layers, the pressure-barrier concept only limits the optimum viscosity of the injected polymer if the mobility of the polymer bank is less than the mobility of the displaced oil bank. The same is true for multi-zoned reservoirs with no crossflow between layers. Thus, for these cases, the optimum polymer viscosity is likely to be dictated by the mobility of the oil bank, unless other factors (like fracture extension) intervene. For multi-zoned reservoirs with free crossflow between layers, the situation is different. A compromise must be reached between injected polymer viscosity and the efficiency of oil recovery. The relevance of our findings is applied to operations for several existing polymer floods. This work is particularly relevant to viscous-oil reservoirs (like Pelican Lake and others) where the injected polymer viscosities are substantially lower than the oil viscosity
- North America > Canada > Alberta (0.89)
- North America > United States > Texas (0.68)
- Asia > China > Heilongjiang Province > Daqing (0.26)
- South America > Suriname > North Atlantic Ocean > Guyana-Suriname Basin > Tambaredjo Field (0.99)
- South America > Guyana > North Atlantic Ocean > Guyana-Suriname Basin > Tambaredjo Field (0.99)
- North America > United States > Alaska > North Slope Basin > Milne Point Field > Kuparuk Formation (0.99)
- (5 more...)
Novel Application of Polyethylene Oxide Polymer for EOR from Oil-Wet Carbonates
Trine, Eric Brandon (Ultimate EOR Services, LLC) | Pope, Gary Arnold (Ultimate EOR Services, LLC) | Britton, Chris James (Ultimate EOR Services, LLC) | Dean, Robert Matthew (Ultimate EOR Services, LLC) | Driver, Jonathan William (Ultimate EOR Services, LLC)
Abstract The objective of this study was to test the performance of high-molecular weight polyethylene oxide (PEO) polymer in a low-permeability, oil-wet carbonate reservoir rock. Conventional HPAM polymers of similar molecular weight did not exhibit acceptable transport in the same rock, so PEO was explored as an alternative polymer. Viscosity, pressure drop across each section of the core, oil recovery, and polymer retention were measured. The PEO polymer showed good transport in the 23 mD reservoir carbonate core and reduced the residual saturation from 0.29 to 0.17. The reduction of residual oil saturation after polymer flooding using PEO was unexpected and potentially significant.
- Energy > Oil & Gas > Upstream (1.00)
- Materials > Chemicals > Commodity Chemicals > Petrochemicals (0.88)
Miniature Viscosity Sensors for EOR Polymer Fluids
Gonzalez, Miguel (Aramco Services Company: Aramco Research Center—Houston) | Ayirala, Subhash (Exploration and Petroleum Engineering Advanced Research Centre, EXPEC ARC, Saudi Aramco) | Maskeen, Lyla (Exploration and Petroleum Engineering Advanced Research Centre, EXPEC ARC, Saudi Aramco) | Sofi, Abdulkarim (Exploration and Petroleum Engineering Advanced Research Centre, EXPEC ARC, Saudi Aramco)
Abstract There are currently no technologies available to measure polymer solution viscosities at realistic downhole conditions in a well during enhanced oil recovery (EOR). In this paper, custom-made probes using quartz tuning fork (QTF) resonators are demonstrated for measurements of viscosity of polymer fluids. The electromechanical response of the resonators was calibrated in simple Newtonian fluids and in non-Newtonian polymer fluids at different concentrations. The responses were then used to measure field-collected samples of polymer injection fluids. The measured viscosity values by tuning forks were lower than those measured by the conventional rheometer at 6.8 s, indicating the effect of viscoelasticity of the fluid. However, the predicted rheometer viscosity versus QTF measured viscosity showed a perfect exponential correlation, allowing for calibration between the two viscometers. The QTF sensors were shown to successfully produce accurate viscosity measurements of polymer fluids within the required polymer concentration ranges used in the field, and predicted field sample viscosities with less than 5% error from the rheometer data. These devices can be easily integrated into portable systems for lab or wellsite deployment as well as logging tools for downhole deployment.
- Energy > Oil & Gas > Upstream (1.00)
- Materials > Chemicals > Commodity Chemicals > Petrochemicals (0.47)
Development of Bio-Based Surfactant Foams for Hydrocarbon Gas Disposal Applications
Jin, Julia (Chevron Technical Center, a Division of Chevron USA Inc.) | Zuo, Lin (Chevron Technical Center, a Division of Chevron USA Inc.) | Pinnawala, Gayani (Chevron Technical Center, a Division of Chevron USA Inc.) | Linnemeyer, Harold (Chevron Technical Center, a Division of Chevron USA Inc.) | Griffith, Christopher (Chevron Technical Center, a Division of Chevron USA Inc.) | Zhou, Jimin (Chevron Technical Center, a Division of Chevron USA Inc.) | Malik, Taimur (Chevron Technical Center, a Division of Chevron USA Inc.)
Abstract There has been increasing interest in different greenhouse gas (GHG) management strategies including the reduction of methane emissions and carbon sequestration. It has been proposed that reinjection of excess produced natural gas can mitigate GHG emissions without compromising oil production. Foam has been used as a method to reduce gas mobility, delay gas breakthrough, and improve sweep efficiency. However, industrial production of petroleum-based chemicals or surfactants to generate foam can be dependent on fossil-based resources that can be scarce or expensive. The main objective of this work was to reduce chemical cost and oil-based chemical dependency by developing an alternative biosurfactant formulation to generate high quality foam. Biosurfactant blends were ranked in comparison to single component anionic and nonionic surfactants and other commercially available surfactant blends. Bulk stability "shake tests" were done to look at initial foamability and stability of the different candidates and then corefloods in sandpacks and surrogate rocks were completed to look at if formulations would generate foam in porous media with methane gas and in the presence of crude oil. Experiments showed success in replicating chemical performance by replacing traditional oil-based surfactants with bio-based lignin derived surfactants even at reservoir conditions. High-quality biosurfactant foams reduced chemical costs, provided an alternative method to dispose of large amounts of hydrocarbon gas, and improved oil recovery through foam displacement.
- Europe > Norway > North Sea > Northern North Sea > East Shetland Basin > PL 375 > Block 34/7 > Snorre Field > Statfjord Group (0.99)
- Europe > Norway > North Sea > Northern North Sea > East Shetland Basin > PL 375 > Block 34/7 > Snorre Field > Lunde Formation (0.99)
- Europe > Norway > North Sea > Northern North Sea > East Shetland Basin > PL 375 > Block 34/4 > Snorre Field > Statfjord Group (0.99)
- (9 more...)
Polymer Injectivity Enhancement Using Chemical Stimulation: A Multi-Dimensional Study
Chandrasekhar, Sriram (Chevron Technical Center, a division of Chevron USA Inc.) | Alexis, Dennis Arun (Chevron Technical Center, a division of Chevron USA Inc.) | Jin, Julia (Chevron Technical Center, a division of Chevron USA Inc.) | Malik, Taimur (Chevron Technical Center, a division of Chevron USA Inc.) | Dwarakanath, Varadarajan (Chevron Technical Center, a division of Chevron USA Inc.)
Abstract Chevron injected emulsion polymer in the Captain field, offshore UK in the last decade at various scales (Poulsen et al., 2018). Pilot horizontal wells had exhibited faster than designed injectivity decline and Jackson et al. (2019) documented the causes to include oleic phase damage from a) injection of produced water containing crude oil after imperfect separation, and b) entrainment of injected emulsion polymer’s carrier oil. The wells were remediated with a surfactant stimulation package (Alexis et al., 2021; Dwarakanath et al., 2016). The remediation boosted the water relative permeability near wellbore which enhanced injectivity and allowed higher processing rates for subsequent continuous polymer injection. In this work, we conducted a set of core floods in slabs of surrogate rock of varying dimension and patterns to demonstrate the beneficial effect of near wellbore stimulation in the general case. 0.04 PV of the remediation package was injected and we show consistent injectivity enhancement across the experiments. We demonstrate the dominant effect of well skin treatment on the pressure drop profile compared to flow resistance from a) residual oil saturation and b) viscous fingering. The result is an important reminder for injectivity maintenance for high polymer flood processing rates for the life of the project. Clean injection fluids were demonstrated to maintain injectivity. We show applicability of stimulation for injectors into viscous oil reservoirs with adverse viscosity ratio. The robust nature of the remediation package developed by Alexis et al. (2021) is also shown, working to efficacy on viscous oil, as well as in situ phase separated polymer. We estimated skin and stimulation depth for a line drive case with low chemical dosage finding that 0.04 pore volumes of surfactant injection at 0.33 oil saturation units gave injectivity improvement of 31%. Surfactant stimulation is thus broadly applicable to wells with oleic phase skin.
Screening of Topside Challenges Related to Polymer Presence in the Back Produced Fluids – Casabe Case Study
Mouret, Aurélie (IFP Energies Nouvelles) | Blazquez-Egea, Christian (IFP Energies Nouvelles) | Hénaut, Isabelle (IFP Energies Nouvelles) | Jermann, Cyril (IFP Energies Nouvelles) | Salaün, Mathieu (Solvay) | Quintero, Henderson (Ecopetrol) | Gutierrez, Mauricio (Ecopetrol) | Acosta, Tito (Ecopetrol) | Jimenez, Robinson (Ecopetrol) | Vargas, Nadine (Ecopetrol)
Abstract Polymer enhanced oil recovery (EOR) pilots were implemented in various mature oilfield reservoirs in Colombia with encouraging results. That chemical EOR technology is often considered as a promising process to faster recover oil. To increase the chance of success of such an industrial project it is important not to neglect the potential impact of residual polymer in back produced effluents. The objective of this work is to highlight the impact of back-produced EOR polymer at the laboratory scale on various topside equipment before deploying the polymer injection at wider scale in a heavy oil field (18° API). A topside facility review was first performed to collect operational conditions and parameters, to identify applied treatment technologies and to define relevant sampling locations for the laboratory study. The impact of the residual acrylamide/ATBS ter-polymer selected for the future polymer implementation was then explored in a set of experiments as part of a dedicated laboratory workflow representing the whole surface treatment chain. The scope of the study has covered primary separation, static gravity water clarifying, deep-bed filtration and heater fouling. Large residual polymer concentration and water cut ranges were investigated to anticipate some produced fluid composition change over time. In the case studied, the selected polymer does not stabilize tight water-in-oil emulsions, but it has a negative impact on the water quality. Some compatibility issues are observed with incumbent demulsifiers, which seems to be sensitive to both polymer concentration and water cut. The fouling risk of heat exchanger is very low in the testing conditions. In the water de-oiling side, filtration and gravity settling performance are reduced but the right chemical and equipment combination enables to obtain a better water quality and to meet injection specifications targets. Novel/Additive Information: This work illustrates that management of produced fluid containing EOR polymer has to be considered as early as possible in the project implementation. It also points out that laboratory experiments are useful to better appraise and mitigate the potential operational issues. All the results obtained in such a study are valuable guideline and input data for treatment facilities upgrade studies. In polymer flooding roadmap implementation, it is key to bond operational conditions and laboratory parameters in order to be as close as possible to the field conditions as each case is unique.
- South America > Colombia (0.67)
- North America > United States (0.46)
- Asia > India (0.46)
- Research Report > New Finding (0.68)
- Research Report > Experimental Study (0.48)
- Water & Waste Management > Water Management > Lifecycle > Treatment (1.00)
- Energy > Oil & Gas > Upstream (1.00)
- South America > Colombia > Santander Department > Middle Magdalena Basin > Yariguí-Cantagallo Field (0.99)
- South America > Colombia > Bolivar Department > Middle Magdalena Basin > Yariguí-Cantagallo Field (0.99)
- South America > Colombia > Antioquia Department > Middle Magdalena Basin > Casabe Field (0.99)
- (8 more...)
- Reservoir Description and Dynamics > Improved and Enhanced Recovery > Chemical flooding methods (1.00)
- Production and Well Operations > Production Chemistry, Metallurgy and Biology > Downhole chemical treatments and fluid compatibility (1.00)
- Health, Safety, Environment & Sustainability > Environment > Water use, produced water discharge and disposal (1.00)
Mobility Of Microemulsions: A New Method to Improve Understanding and Performances of Surfactant EOR
Rousseau, David (IFP Energies nouvelles - The EOR Alliance) | Le Gallo, Clémence (IFP Energies nouvelles - The EOR Alliance) | Wartenberg, Nicolas (Solvay - The EOR Alliance) | Courtaud, Tiphaine (Solvay - The EOR Alliance)
Abstract The mobility of Winsor III microemulsions, which can form in reservoirs when a surfactant formulation contacts oil, has become a critical parameter for feasibility evaluations of surfactant flooding EOR. The reason is that these bicontinous phases with low mobility are likely to impair the sweep efficiency of the remobilized oil. The common procedures to evaluate microemulsion's mobility are based on viscosity measurements. As they involve rheometers, namely pure shear flows, and conditions where microemulsions are separated from the water and oil phases they should remain equilibrated with, they are not satisfactory. We present a new method to directly determine the mobility of microemulsions at equilibrium and in-situ, namely when flowing in porous media. The method consists in preforming the Winsor III microemulsion in a buffer cell and then injecting it in a small sized core plug. The bicontinous phase stays at equilibrium because the oil and water phases, present in the buffer cell, remain in contact with it. The mobility is assessed through the resistance factor (or mobility reduction factor), relative to the water phase injected first. This observable accounts for both viscosity and potential permeability impairment effect. As it directly represents the reduction of the mobility of the water phase, it is representative of phenomena taking place in the reservoir. During a typical experiment, the same microemulsion is also injected in a capillary tube, in order to determine its viscosity in a pure shear flow. Winsor III microemulsions were injected in sandstone plugs of three different permeabilities (1700 to 45 mD), and in a 170 mD carbonate plug. The first outcomes are that the resistance factors in the porous media and capillary relative viscosities have a marked shear-thinning behavior but are always of the same order of magnitude. This indicates that the flow of microemulsions entails no or little permeability impairment. Based on the experimental determination of the porous media's shape factors, the resistance factors and capillary viscosity data were also plotted against the equivalent wall shear rate. For the highest permeability sandstone, the capillary and porous medium data scaled almost perfectly, showing that, in this case, the microemulsion's transport properties are that of an ideal non-Newtonian fluid. However, increasing deviations were observed when decreasing the sandstone permeability as well as for the carbonate porous medium. This suggests that microemulsions are strongly affected by the composite deformations taking place in complex microscopic pore structures. These outcomes show the importance of determining the microemulsion-induced resistance factor in representative conditions in order to forecast for the impact of microemulsion's mobility in reservoirs. Furthermore, the method proposed can be applied to investigate close to optimum conditions as well as to study the propagation of microemulsions.
- Research Report (1.00)
- Overview > Innovation (0.60)
- Energy > Oil & Gas > Upstream (1.00)
- Materials > Chemicals > Commodity Chemicals > Petrochemicals (0.68)
Summary Typical seawater depths for deep-water oil fields range from 1000m to 4000m. For these deep-water oil fields, the most popular and cost-effective technologies for increased oil recovery are water injection and subsea boosting with a multiphase helico-axial pump on the seabed. By installing a pump on the seabed, the well head pressure and thus the bottom hole pressure can be reduced, which will result in an increased well lifetime and thus an increased oil recovery. This contributes to a reduction in CAPEX per produced barrel and hence make the field development economically more interesting. Viscous multiphase production fluids occur in case of a viscous oil or in case of water-oil emulsions with a high apparent viscosity close to the inversion point. It is known that for viscous fluids the required power and size of the pump are significantly larger than for water-like products, such as low viscous oils. On top of this, due to the poor accuracy of the existing performance prediction models available in literature for viscous conditions, the pumps and the corresponding utility systems have to be significantly over-dimensioned to compensate for the uncertainties. This has a large negative impact on the CAPEX requirements for such field developments up to the point that it becomes economically unattractive to develop the field. For this reason, TotalEnergies (Operator), Sulzer (OEM) and TechnipFMC (EPC contractor) have launched real-size pump test campaigns in 2012 and 2014 with viscosities up to 3,000 cP in hot fluid and 10,000 cP in cold start-up conditions. The data obtained from those measurement campaigns have been used to develop a performance prediction model, which allows for accurate sizing of the pumps and corresponding topside utility system. This model allows for a reduction of the uncertainties and risks related to subsea boosting for viscous deep-water field developments and related to this the overall CAPEX requirements. This enables subsea boosting as a viable solution for increased oil recovery for deep-water fields with viscous multiphase fluids. This paper presents the test campaign and acquired measurement data. It explains how the effect of viscosity is modeled. It illustrates the match between the pump performance prediction model and the viscous multiphase test data. This allows for a reduction of the uncertainties and thus a more accurate pump selection.