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Collaborating Authors
Williston Basin
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)
Abstract Water is accumulated near the fracture surface after fracturing, which will block oil flow out. The water blockage can be mitigated through the immediate well flow back or through shutting in the well before flow back. Which method is more effective? There are mixed results in the literature from field reports and experimental or simulation studies. This paper discussed the literature results and simulation data obtained from this study. It is found that the oil recovery mainly depends on the magnitude of pressure drawdown and the strength of imbibition. When the pressure drawdown is high, immediate flow back may lead to higher oil recovery than shutting in a well before flow back. When imbibition is strong, shutting in may be beneficial to enhance oil recovery through counter-current flow. Although many parameters of reservoir properties and operations may affect the shut-in effect, those parameters may be grouped into the pressure drawdown and imbibition strength. The parameters of matrix permeability, wettability, initial water saturation, and formation compressibility are discussed. Analysis and discussion of simulation data also suggest that the oil recovery is a linear function of pressure drawdown, but the relationship between oil recovery and capillary pressure is non-linear and more complex. The results and discussion from this study suggest that the immediate flow back may outperform the shut-in if a large pressure drawdown is applied. If a reservoir provides a strong imbibition condition, the shut-in may be beneficial. Surfactants may be chosen to enhance imbibition. The surfactants which alter the reservoir from oil-wet to water-wet may be preferred.
- Research Report > New Finding (0.68)
- Research Report > Experimental Study (0.54)
- North America > United States > West Virginia > Appalachian Basin > Marcellus Shale Formation (0.99)
- North America > United States > West Virginia > Appalachian Basin > Marcellus Field > Marcellus Shale Formation (0.99)
- North America > United States > Virginia > Appalachian Basin > Marcellus Shale Formation (0.99)
- (10 more...)
Abstract The wettability of tight reservoir rock plays a critical role in affecting relative permeability and in turn oil recovery. However, the link between wettability and its effects on oil recovery remains poorly understood, and the potential to boost oil recovery by varying the wettability has not been fully explored. This work was an attempt to conduct a systematic experimental study to improve our understanding of wettability of tight oil reservoirs and the mechanisms of its alteration on oil recovery improvement. Contact angles of individual rock-forming minerals and reservoir rock samples were first measured in brines with different salinities. Then the minerals were aged separately with a medium crude oil with sufficient polar components to investigate their tendency for wettability alteration. As well, oil and water distributions inside tight core samples were scanned by a synchrotron-based computed tomography scanner. Contact angle measurements for all minerals and reservoir rocks showed initial water-wetting behavior. After aging with crude oil for over two months, polar components from the oil adsorbed onto the solid surfaces to alter their wettability to less water wet. Consequently, this wettability alteration contributed to oil and water redistribution and saturation change in reservoir cores. The experimental findings suggested that the wettability in tight reservoirs is a strong function of rock mineralogy, formation fluid properties, and saturation history. Preliminary numerical simulation revealed how rock wettability alteration could contribute to improved oil recovery through waterflooding.
- North America > Canada > Saskatchewan (0.95)
- North America > United States > North Dakota (0.94)
- Research Report > New Finding (0.88)
- Research Report > Experimental Study (0.54)
- 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)
- (4 more...)
- Reservoir Description and Dynamics > Reservoir Fluid Dynamics > Flow in porous media (1.00)
- Reservoir Description and Dynamics > Reservoir Characterization > Exploration, development, structural geology (1.00)
- Reservoir Description and Dynamics > Improved and Enhanced Recovery > Waterflooding (1.00)
- Reservoir Description and Dynamics > Formation Evaluation & Management > Core analysis (1.00)
Abstract The goal of this work is to develop surfactant systems that can improve oil flow from shale wells after fracturing or re-fracturing. Surfactants can reduce oil-water interfacial tension and wettability of the shale, which in turn can improve water imbibition, increase oil relative permeability and reduce water blockage at the matrix-fracture interface. Temperature in typical shale reservoirs are high and the surfactants need to be aqueous stable to be effective in these treatments. Mixing two surfactants often gives higher aqueous stability than those of the single surfactants. A large number of surfactants (anionic, non-ionic and cationic) and their blends were studied for aqueous stability, contact angle and spontaneous imbibition. Seven single surfactants and nine surfactant blends were found to be stable in both high and low salinity brines at 125 °C. All aqueous stable blends changed wettability of oil-wet shale to preferentially water-wet in both high and low salinity brines. Seven single surfactants and five surfactant blends were tested for imbibition. Surfactant solutions improved water imbibition to the extent of 20% PV. Surfactant blends improved imbibition more than the single surfactants. Imbibition in cores reached a plateau in about 3 days. Surfactant blends have the potential to be used in low salinity fracturing or refracturing fluids to stimulate shale wells.
Abstract The application of surfactants to improve oil recovery in conventional reservoirs via wettability alteration and enhancement of spontaneous imbibition has been extensively studied in the literature. However, little work has been performed yet to investigate the interaction of these surfactants with ultra-tight oil-rich shale reservoirs such as Wolfcamp shale. The use of horizontal drilling and massive multistage hydraulic fracturing has made primary oil recovery from these ultra-tight oil-rich shale reservoirs possible. With declining production from existing shale wells, it is essential to explore potential "beyond primary" strategies in shale oil development. This paper analyzes the potential of surfactants in altering wettability and improving the process of spontaneous imbibition in oil rich shales demonstrating nanodarcy range permeability, relevant to stimulation and "beyond primary" chemical EOR applications in shales. Novel proprietary surfactant blends along with traditional nonionic surfactants were investigated in this study using Wolfcamp shale core samples exhibiting nanodarcy permeability. X-ray diffraction analysis was performed which indicated that Wolfcamp shale has mixed mineralogy, with quartz, calcite, and dolomite acting as the major minerals in varying proportions depending on the interval depth. Contact angle and interfacial tension measurements were performed at reservoir temperature to identify the state of native wettability and the impact of surfactants in altering wettability. Thereafter, spontaneous imbibition experiments were performed using 3D computed tomography methods to understand the improvement in the magnitude of imbibition penetration due to surfactant addition. Contact angle and spontaneous imbibition experiments showed that Wolfcamp shale is intermediate-wet and surfactants have the potential to alter the native wettability to a preferentially water-wet state and improve oil recovery due to enhanced spontaneous imbibition. Surfactants which altered the wettability significantly, but lowered the interfacial tension only slightly showed the highest oil recoveries due to the creation of strong capillary driven forces directly responsible for effective spontaneous imbibition. The potential of surfactants in altering wettability and improving oil recovery via enhanced spontaneous imbibition in ultra-tight oil-rich shales was verified in this study. The effectiveness of traditional nonionic surfactants in altering wettability and improving oil recovery was found to be comparable to that of novel, more expensive proprietary surfactant blends, and hence, the traditional nonionic surfactants provide a cost effective option for stimulation and EOR applications in Wolfcamp shale. Overall, this paper presents the theory behind surfactant interaction with ultra-tight shales and provides experimental results to validate the viability of surfactant induced improved oil recovery in shales.
- North America > United States > Texas (1.00)
- North America > United States > New Mexico (1.00)
- 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)
- (29 more...)
Abstract Fracture treatment performance in Bakken shale reservoirs can be improved by altering rock wettability, as measured with contact angle (CA), from oil-wet to water-wet. The use of chemical additives for altering wettability also results in alteration of the interfacial tension (IFT). The Young-Laplace equation relates the capillary pressure to IFT and contact angle. Thus, it follows that capillarity is significant in nano-pores associated with unconventional liquid reservoirs (ULR) and complex as the CA and IFT varies simultaneously. We carefully evaluate these interactive variables to improve oil recovery by alteration of capillary pressure by understanding the wetting state of siliceous and carbonate Bakken cores with and without chemical additives. We have observed that wettability can be altered from the ULR natural state of oil-wet to systems favoring frac fluid imbibition. Surfactants can be added to completion fluids, in proper concentrations, to alter wettability while hydraulic fracturing the formation. This experimental study evaluates and compares the efficiency of anionic, nonionic and blended surfactants as well as complex nanofluids (CNF) on recovering liquid hydrocarbons from Bakken shale cores by analyzing the effect of wettability and IFT alteration and their impact on spontaneous imbibition. The original wettability of Bakken cores is determined by CA measurements. Then, three surfactant types, anionic nonionic and nonionic-cationic, and CNF are evaluated to gauge their effectiveness in altering wettability. The results show that all surfactants and CNF are able to shift core wettability from oil-wet to water-wet. However, chemical additives efficacy strongly depends on rock lithology, surfactant, and CNF type. Moreover, to evaluate further wettability alteration, stability of surfactant and CNF solution films on the shale rock surface is determined by zeta potential measurements. Surfactants and CNF show higher zeta potential magnitudes than water without additives, as an indication of better stability and water-wetness, which agrees with CA results. In addition, the effect of IFT alteration is studied in solutions with surfactants and CNF, and Bakken crude oil. Higher IFT reduction is achieved by anionic surfactants, but all surfactants and CNF perform better than water alone. Surfactants and CNF potential for improving oil recovery in ultralow permeability Bakken cores is investigated by spontaneous imbibition experiments using modified Amott cells in an environmental chamber. Using computed tomography (CT) scan methods, water imbibition as penetration magnitude is measured in real time. In addition, oil recovery is recorded with time to compare the performance of surfactants, CNF, and completion fluid alone. The results suggest that surfactants and CNF are better on recovering oil from shale core displacing more oil and having higher penetration magnitudes than water without additives. In addition, oil recovery depends on surfactant and CNF type and rock mineral composition. These findings are consistent with CA, zeta potential, and IFT measurements. From the results obtained, it can be concluded that altering wettability and reducing IFT when surfactants and CNF additives are added to completion fluids can improve oil recovery in Bakken cores.
- North America > United States > South Dakota (1.00)
- North America > United States > North Dakota (1.00)
- North America > United States > Montana (1.00)
- Research Report > New Finding (1.00)
- Research Report > Experimental Study (1.00)
- 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)
Optimizing Water Chemistry to Improve Oil Recovery from the Middle Bakken Formation
Wang, D.. (University of North Dakota) | Dawson, M.. (Statoil Gulf Services LLC) | Butler, R.. (University of North Dakota) | Li, H.. (Statoil Gulf Services LLC) | Zhang, J.. (University of North Dakota) | Olatunji, K.. (University of North Dakota)
Abstract With the recent dramatic drop in oil price, production from ultra-tight resources, like the Bakken formation, may drop substantially. Since expenditures for drilling, completion, and fracking have already been made, existing wells will continue to flow, but oil rates will decline—rapidly in many cases. In a low oil-price environment, what can be done to sustain oil production from these tight formations? We are testing a surfactant imbibition process to recovery oil from shales. We measured surfactant imbibition rates and oil recovery values in laboratory cores from the Bakken shale. After optimizing surfactant formulations at reservoir conditions, we observed oil recovery values up to 10–20% OOIP incremental over brine imbibition. However, whether or not surfactant imbibition will be a viable recovery process depends on achieving sufficiently high oil production rates in a field setting—which requires that we identify conditions that will maximize imbibition rate, as well as total oil recovery. In this paper, we describe laboratory evaluations of oil recovery using different core plugs. These recovery studies involved (1) surfactant formulation optimization on concentration, salinity and pH, (2) characterization of phase behavior, (3) spontaneous imbibition, and (4) forced imbibition (flooding) with gravity drainage assistance. In preserved cores, we observed: (1) Formulations using 0.1% surfactant concentration at 4% TDS salinity showed favorable oil recoveries (up to 40% OOIP). (2) Generally, surfactant formulations at optimal concentration and salinity were stable at high temperature (115°C). (3) Injectivity/permeability enhancements up to 75 percent occurred after acidification using acetic acid or HCl. (4) Wettability alteration is the dominant mechanism for surfactant imbibition. Of course, actions that increase fracture width will aid gravity drainage and oil recovery. This information is being used to design and implement a field application of the surfactant imbibition process in an ultra-tight resource.
- North America > United States > North Dakota (1.00)
- North America > Canada > Saskatchewan (1.00)
- North America > Canada > Manitoba (1.00)
- Energy > Oil & Gas > Upstream (1.00)
- Materials > Chemicals > Commodity Chemicals > Petrochemicals (0.68)
- North America > United States > South Dakota > Williston Basin > Bakken Shale Formation (0.99)
- North America > United States > North Dakota > Williston Basin > Bakken Shale Formation > Middle Bakken Shale Formation (0.99)
- North America > United States > Montana > Williston Basin > Bakken Shale Formation (0.99)
- (4 more...)