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Results
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.
Use of Horizontal Injectors for Improving Injectivity and Conformance in Polymer Floods
Hwang, Jongsoo (The University of Texas Austin) | Zheng, Shuang (The University of Texas Austin) | Sharma, Mukul (The University of Texas Austin) | Chiotoroiu, Maria-Magdalena (OMV Exploration & Production GmbH) | Clemens, Torsten (OMV Exploration & Production GmbH)
Abstract Several field cases have demonstrated polymer injection in a horizontal well increases oil recovery. It is important to maintain high injectivity while preventing injection-induced fractures to ensure good reservoir sweep. Our primary goal in this paper is to better understand polymer injection data from horizontal injectors in the Matzen field using a fully integrated reservoir, geomechanics, and fracturing model. By simulating polymer injection history, we present several advantages of horizontal injectors over the vertical wells. Horizontal injectors delay fracture initiation and provide better tolerance to polymer plugging on the wellbore surface. Simulations explain the measured PLT data of fluid distributions influenced by accumulated polymer deposition in multiple zones. We show that gradual injectivity decline is attributed to both polymer filter cake buildup and high-viscosity, shear-thickening zones created around the wellbore. The field case simulation also clarifies the flow distribution in different sands and how polymer rheology affects this. This distribution is found to be different than for water injection. Results from periodic acid treatments clearly show that free-flowing particles in the polymer solution are responsible for formation damage. Polymer plugging and the viscous pressure drop in the shear-thickening zone are the primary factor affecting the measured injection pressure. Based on the strong near-wellbore viscosity impact, geomechanical simulations identify reservoir zones prone to fracture growth during long-term injection, and we suggest strategies to avoid injection induced fractures that can lead to poor conformance.
- Europe (1.00)
- North America > United States > Alaska (0.28)
- North America > United States > Texas (0.28)
- Geology > Geological Subdiscipline > Geomechanics (1.00)
- Geology > Rock Type > Sedimentary Rock > Clastic Rock (0.47)
- Energy > Oil & Gas > Upstream (1.00)
- Water & Waste Management > Water Management > Lifecycle > Disposal/Injection (0.51)
- North America > United States > Texas > Permian Basin > Yeso Formation (0.99)
- North America > United States > Texas > Permian Basin > Yates Formation (0.99)
- North America > United States > Texas > Permian Basin > Wolfcamp Formation (0.99)
- (37 more...)
Abstract Alkaline-Surfactant-Foam flooding is a novel enhanced oil recovery process which increases oil recovery over water flooding by combining lowering of the oil-water interfacial tension by two to three orders of magnitude and foaming. We report an experimental study of the formation of the oil bank and its displacement by foam drives of varying qualities. Experiments include: (a) bulk phase behaviour and foam testing studies using n-hexadecane and a single internal olefin sulfonate surfactant which was found to lower the oil-water interfacial tension by at least two orders of magnitude and (b) series of CT scanned core-floods using Bentheimer sandstone cores. A major goal of this study was to investigate the effect of drive foam quality on oil bank displacement. Core-flood results, performed at under-optimum salinity conditions yielding an oil-water interfacial tension in the order of 10 mN/m, showed similar ultimate oil recovery factors for the range of drive foam qualities studied. Although the total oil recovery is not affected by drive foam quality, results indicate a more frontal oil bank displacement at lower foam qualities. The findings in this study suggest that a) a lower drive foam quality favours oil bank displacement and b) the amount of clean oil produced by the oil bank is not effected by drive foam quality.
- Energy > Oil & Gas > Upstream (1.00)
- Materials > Chemicals > Commodity Chemicals > Petrochemicals (0.34)
- Reservoir Description and Dynamics > Reservoir Fluid Dynamics > Flow in porous media (1.00)
- Reservoir Description and Dynamics > Improved and Enhanced Recovery > Waterflooding (1.00)
- Reservoir Description and Dynamics > Improved and Enhanced Recovery > Gas-injection methods (1.00)
- Reservoir Description and Dynamics > Improved and Enhanced Recovery > Chemical flooding methods (1.00)
General Overview This paper describes a new chemical EOR numerical model capable of simulating surfactant and polymer floods. We present the highlights of a highly efficient and robust IMPES implementation within a legacy, in-house gas-oil-water compositional simulator. The additional computational overhead, over say a waterflood calculation, is on the order of only 20% for large scale (type pattern model) simulations. We present performance results both in serial as well as parallel (multi-processor) mode. Flow within all three Winsor Type environments is modeled, with the ability to transition between the different types. The effects of a separate microemulsion (ME) phase are accounted for. Temperature effects on surfactant phase behavior as well as on adsorption are also considered. Other important physical effects that are modeled include phase trapping and oil bypassed by surfactant, near wellbore polymer injectivity and the reduction of surfactant adsorption associated with a sacrificial agent such as alkali. Gas phase is included in the model. The model has been extensively benchmarked against another reservoir simulator. We also present some validation results at the laboratory as well as at the field scale.
Dynamic Field Rheology, Filterability and Injectivity Characterization Using a Portable Measurement Unit
Espinosa, David (Chevron) | Walker, Dustin (Chevron) | Alexis, Dennis (Chevron) | Dwarakanath, Varadarajan (Chevron) | Jackson, Adam (Chevron) | Kim, Do Hoon (Chevron) | Linnemeyer, Harold (Chevron) | Malik, Taimur (Chevron) | McKilligan, Derek (Chevron) | New, Peter (Chevron) | Poulsen, Anette (Chevron) | Winslow, Greg (Chevron)
Abstract Field deployment of Chemical EOR floods requires monitoring of wellhead injection fluids to ensure field performance is commensurate with laboratory design. Real-time surveillance allows for optimizing chemical use, detecting potential issues, and ensures correct chemical handling. In an offshore setting traditional surveillance methods can present unique challenges due to space constraints, field conditions, and location. We present a novel approach to field surveillance using a portable measurement unit (PMU) that can dynamically characterize polymer rheology, filterability and long-term core-injectivity. We developed a PMU and placed it inside a suitcase sized box (42x26x20″) with appropriate devices to measure polymer rheology, filterability and long-term core injectivity. Polymer rheology was measured using a series of capillary tubes with pressure measurements. Filterability was measured through a 1.2 um filter at 15 psi with coarse filtration to remove large oil droplets and suspended solids. This was compared against filterability without filtration to observe water quality impact. Finally, long-term injectivity was measured using an epoxy-coated Bentheimer core with a pressure tap to quantify whether there was any face and/or core-plugging. By constructing this apparatus, wellhead injection fluids under anaerobic conditions can be monitored and analyzed to improve fluid quality assurance and contribute to a project's success even in challenging and remote locations. The use of the PMU is critical for dynamic fluid surveillance. The injection solutions consistently met or exceeded target viscosity of 20 cP. Furthermore, the coarse-filtered solutions also met a filtration ratio (FR) requirements of less than 1.5 at 15 psi through 1.2 micron filters. The unfiltered solutions achieved a FR of 1.75, which was considered acceptable. Finally, no plugging was observed with coarse-filtered solutions after 25 PV across the whole core and > 75 PV across the core face. Further testing was completed with wellhead injectate samples at variable operating conditions to establish a baseline for chemical flooding operations and provided insight for future facilities design. The information these experiments produced helped identify and diagnose facility and operational issues that would have caused negative consequences with the chemical injection had the configuration been used without the PMU surveillance. By testing the wellhead fluid, we determined that there was improper dosing of the chemical. This was determined by comparing the field fluid properties to expected results from the lab. The data also influenced facilities design and in turn improved the chemical and project efficiency. By testing the injectate at different operating conditions we could determine the operating envelope for the current injection facilities and base future work on the results. All of this was done in real time on an offshore platform, as opposed to sending samples onshore to test which yields unrepresentative results from the time delay and fluid quality changes during transport.
- North America > United States > Texas (0.47)
- North America > United States > Oklahoma (0.30)
- North America > United States > Louisiana > Pelican Lake Field (0.99)
- Europe > United Kingdom > North Sea > Central North Sea > Moray Firth > Moray Firth Basin > Block 13/22a > Captain Field > Captain Formation (0.99)
- Asia > India > Rajasthan > Rajasthan Basin > Barmer Basin > Rajasthan Block > Mangala Field > Fatehgarh Formation (0.99)
- (3 more...)
Abstract The goal of this research is to improve oil recovery by reducing bypassing due to fractures, common in carbonate reservoirs. Salinity sensitive polymeric particles (SSPP) are synthesized in this study, which can plug fractures in reservoir rocks and divert fluid flow into the matrix. SSPP swell in brine; the swelling is a function of brine salinity. SSPP expand many times (~70 times) in DI water, but swell only about 3 times in very high salinity (20 wt% NaCl) brine. The swelling of the particles is independent of pH in the range of 2 to 12.6. The swelling process is reversible with salinity. These particles are stable at 60 °C for at least several months. Core flood results show that these small particles can be transported through fractures during high salinity brine injection and plug the fractures during low salinity brine injection. Then the injectant fluid flow is diverted into the matrix and recovers oil from previously unswept matrix. SSPP injection increases waterflood recovery in cores with full fractures and half fracture connected to the inlet. The SSPP placement also increases oil recovery for tertiary miscible floods.
- Research Report > New Finding (0.86)
- Research Report > Experimental Study (0.66)
- Energy > Oil & Gas > Upstream (1.00)
- Materials > Chemicals > Commodity Chemicals > Petrochemicals (0.31)
- North America > United States > Texas > Permian Basin > Yeso Formation (0.99)
- North America > United States > Texas > Permian Basin > Yates Formation (0.99)
- North America > United States > Texas > Permian Basin > Wolfcamp Formation (0.99)
- (22 more...)
Abstract Wettability of the rock is an important parameter in determining oil recovery. It determines the fluid behavior and the fluid distribution in the reservoir. Aging of the rock changes the wettability of the rock and can affect the residual oil saturation. This paper investigates the effect of aging on the oil recovery during the Water-Alternating-CO2 injection (WACO2) process using 20 in. outcrop Grey Berea sandstone cores under immiscible conditions. In the present work, two coreflood experiments were performed. Both cores were aged for a period of 30 days at 149°F. This study is a continued research and compares the performance of WACO2 injection in aged cores to previously published work with unaged cores. All experiments were done at 500 psi and in the secondary recovery mode. The wettability of the Rock- Brine-CO2-Oil system for aged cores was determined by contact angle measurements using formation brine (174,156 ppm), seawater brine (54,680 ppm) and low-salinity brine (5,000 ppm NaCl). The interfacial tension (IFT) of the Brine-Oil-N2 and Brine-Oil-CO2 system was also measured using the axisymmetric drop shape analysis (ADSA) method. Computerized tomography (CT) scans were obtained for each core in its various states: dry state, 100% water-saturated state, oil saturated state with irreducible water saturation, and residual oil-saturated state. The CT scans were used to determine the porosity profile of the cores. The contact angle measurements of the Rock - Brine - CO2 - Oil system indicated an increase in contact angles after the aging of the cores. Low-salinity brine showed the most water-wet state (55°) and seawater brine showed the most oil-wet state (96°) of the rock. This may be because of the increased concentration of divalent ions on the surface of the rock during seawater brine injection. Ion binding is the dominant mechanism in the oil-wet nature of the rock. The previously published work stated that the coreflood experiments of the unaged cores resulted in an oil recovery of 61.7 and 64.6% OOIP during low-salinity water-alternating-CO2 and seawater-alternating-CO2 injection, respectively. In aged cores, the oil recovery increased to 97.7 and 76.1% OOIP during the low-salinity water-alternating-CO2 and seawater-alternating-CO2 injection, respectively. The improved oil recovery was attributed to the wettability alteration when the rock was aged. The interfacial tension measurements of brine/oil/nitrogen and brine/oil/CO2 systems showed that the salinity of the brine had an effect on the IFT. Low-salinity brine (5,000 ppm) yielded the highest IFT values and seawater brine produced the least. Monovalent ions had a weak effect on the interfacial activity between the oil and the brine. When multivalent ions were present, the IFT values were influenced by the salting effect of the brines. During the IFT measurements of brine/oil/CO2 system, the IFT values showed an increasing trend as a function of time and then stabilized. The increase in IFT was because of the initial mass transfer between the CO2, brine, and oil phases.
- Asia > Middle East > Saudi Arabia (0.28)
- North America > United States > Oklahoma (0.28)
- North America > United States > West Virginia (0.26)
- (3 more...)
- Geology > Mineral (0.93)
- Geology > Rock Type > Sedimentary Rock > Clastic Rock > Sandstone (0.36)
Abstract Disproportionate permeability reduction (DPR) may provide field solutions to address high volumes of water production and efficiency of oil recovery in non-communicating layered reservoirs. This work evaluates the lab-scale DPR effectiveness at different formation wettability conditions using an environmentally friendly, water-soluble, silicate gelant. A robust, time/temperature stable and easy-to-design water-soluble silicate gelant system is utilized to conduct DPR treatments in oil- and water-wet cores using a newly established steady-state, two-phase chemical system placement. The experimental procedure is applied to ensure the presence of moveable oil saturation at which the injected DPR fluid (gelant) gels in the treated zone and to quantitatively control the placement saturation conditions in the formation. DPR treatments are conducted using a steady-state, two-phase (oil/gelant) placement to better control the water/oil saturation at which the silicate gel sets. The performance of water-soluble, silicate-based DPR treatments are evaluated using pre- and post-treatment two-phase (brine/oil) steady-state and unsteady state permeability measurements. Strongly water-wet Berea cores are chemically treated to alter their wettability to oil wet and measured phase effective permeability curves are used to characterize the newly established core wettability. Treatment design should include filterability/injectivity and rheological studies of the DPR fluid to evaluate gelant interaction with the formation as well as gelation time and kinetics. Single-phase DPR fluid injectivity through Berea cores is excellent. At relatively high watercuts in water-wet cores, two-phase DPR-fluid/oil injectivity is good and even better in oil-wet cores regardless the watrecut. At relatively low watercuts in water-wet cores, the injectivity is not as good as in higher watercuts and the mobility reduction keeps increasing with the co-injection of the DPR-fluid/oil. DPR-fluid/oil placement experiments conducted at the same saturation conditions and water/oil ratio (WOR) showed that the ultimate oil residual resistance factor in oil-wet cores is significantly lower than the one in water-wet cores. This is mainly due to more favorable oil-phase continuity and distribution in oil-wet media compared to the corresponding ones in water-wet formations. In water-wet cores, encapsulation of oil by gel may cause oil-phase discontinuities and porous medium conductivity reduction. Wettability tests have shown that silicate gel is strongly water-wet. Therefore, in oil-wet DPR treatments, formed gel in porous media yields a mixed-wet formation and a lower trapped oil saturation compared to the water-wet formation. In either wetting state, relative permeability hysteresis was insignificant during the post-DPR treatment imbibition/drainage cycles. This also reflects stable gels during post-DPR treatment floods. DPR treatments conducted at high WOR in oil-wet cores have shown a minor gel "erosion" during the post-treatment two- and single-phase (water) injection; gel "erosion" ceased during oil injection. DPR treatments conducted at high WOR caused an increase in residual resistance factor (RRF) of both water and oil phases regardless the core's wetting conditions; the DPR effectiveness was more pronounced in oil-wet cores than in water-wet ones.
- Europe (1.00)
- North America > United States > Texas (0.46)
- North America > United States > Alaska > North Slope Basin > Prudhoe Bay Field (0.99)
- Europe > Norway > North Sea > Northern North Sea > North Viking Graben > Block 30/6 > Veslefrikk Field > Statfjord Group Formation (0.99)
- Europe > Norway > North Sea > Northern North Sea > North Viking Graben > Block 30/6 > Veslefrikk Field > Dunlin Group Formation (0.99)
- (4 more...)
Modeling and Upscaling Unstable Water and Polymer Floods: Dynamic Characterization of the Effective Finger Zone
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)
Abstract 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.
- Asia (1.00)
- North America > United States > Texas (0.94)
- North America > Canada (0.69)
- North America > United States > Louisiana > Pelican Lake Field (0.99)
- Asia > Middle East > Oman > Dhofar Governorate > South Oman Salt Basin > Marmul Field > Al-Qalata Formation (0.99)
- North America > United States > Louisiana > China Field (0.97)
- North America > Canada > Alberta > Western Canada Sedimentary Basin > Alberta Basin > Deep Basin > Mannville Field > Cardium Formation > 2244572 Alberta Mann 16-10-50-10 Well (0.97)
- Reservoir Description and Dynamics > Unconventional and Complex Reservoirs > Oil sand, oil shale, bitumen (1.00)
- Reservoir Description and Dynamics > Reservoir Fluid Dynamics > Flow in porous media (1.00)
- Reservoir Description and Dynamics > Improved and Enhanced Recovery > Waterflooding (1.00)
- Reservoir Description and Dynamics > Improved and Enhanced Recovery > Chemical flooding methods (1.00)
Improving Recovery of a Viscous Oil Using Optimized Emulsion Viscosity
Aminzadeh, Behdad (Chevron Energy Technology Company) | Hoang, Viet (Chevron Energy Technology Company) | Inouye, Art (Chevron Energy Technology Company) | Izgec, Omer (Chevron Energy Technology Company) | Walker, Dustin (Chevron Energy Technology Company) | Chung, Doo (Chevron Energy Technology Company) | Nizamidin, Nabijan (Chevron Energy Technology Company) | Tang, Tom (Chevron Energy Technology Company) | Lolley, Chris (Chevron Energy Technology Company) | Dwarakanath, Varadarajan (Chevron Energy Technology Company)
Abstract Alkali flooding in heavy oil reservoirs is known to stabilize emulsion in-situ and improve the recovery beyond that of conventional waterflood under certain boundary and initial conditions. The overarching goal of this study is to develop a systematic approach to optimize this process and capture underlying recovery mechanisms. Therefore, we experimentally evaluated the performance of alkali flood as a function of emulsion type and viscosity. Phase behavior and viscosity of the microemulsion are modified by introducing seven different surfactants. Microscope imaging techniques are employed to measure the droplet size distribution for type I and II emulsions. Viscosities of generated emulsions are measured with a rotational rheometer at low temperatures and with an electromagnetic viscometer at reservoir conditions. Finally, corefloods are conducted at different conditions to evaluate the performance of displacement as a function of emulsion type and viscosity. Enhanced alkali floods showed an incremental recovery of 8 – 50% beyond that of waterflood. Formation of higher viscosity emulsion has a large contribution on the sweep efficiency and therefore improved oil recovery during alkali flood; however, other mechanisms (e.g. entrainment and entrapment) also have contribute to the incremental recovery. Results of our experiments indicated that the incremental recovery is a strong function of emulsion type, emulsion viscosity, and the droplet size distribution.
- North America > United States > Texas (0.46)
- North America > United States > California (0.28)
- North America > Canada > Alberta (0.28)
- North America > United States > Louisiana > Pelican Lake Field (0.99)
- North America > Canada > British Columbia > Peace River Field (0.99)
- Reservoir Description and Dynamics > Unconventional and Complex Reservoirs > Oil sand, oil shale, bitumen (1.00)
- Reservoir Description and Dynamics > Reservoir Fluid Dynamics > Flow in porous media (1.00)
- Reservoir Description and Dynamics > Improved and Enhanced Recovery > Waterflooding (1.00)
- Reservoir Description and Dynamics > Improved and Enhanced Recovery > Chemical flooding methods (1.00)