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Collaborating Authors
Results
Abstract In order to understand the effect of injected stimulation fluids on nano-darcy permeability, naturally fractured shale reservoirs, an integrated study of spontaneous imbibition was performed. In this study, oil recovery during spontaneous imbibition in naturally fractured shale samples was investigated using different water formulations. Different water solutions were formulated by adding different amounts of HCl and NaOH to either distilled water or 2 wt% KCl-base brine solution. Eight water formulations, distilled water, 2% KCl brine, low pH HCl solutions (0.74-1.2), and high pH alkaline solutions (11.78-12.4) were examined to recover oil from shale rocks. Outcrop samples from Marcellus shale formation were used in this study. The samples were 2.54 to 3.81 cm in diameter and 0.762 to 5.08 cm in length. Firstly, we studied the average porosity of the used samples using CT Scanning. The average porosity was around 6%. Secondly, we studied the rock stability and spontaneous imbibtion of the different Marcellus samples in distilled water, 2 wt% KCl, low pH solutions (0.741.2), and high pH alkaline solutions (11.78-12.43). During the spontaneous imbibition, the maximum oil recovery was 4% using low pH solution of pH0.74 (3 wt% HCl in 2 wt% KCl base brine solution) or high pH solutions (pH11.9 and pH12.4). There was no difference between the oil recoveries achieved by distilled or 2 wt% KCl solution which might indicate that Marcellus shale is not sensitive to salinity. Oil recoveries from Marcellus shale slightly improved when using low or high pH solutions due to wettability alteration that has been supported by the changes in the measured contact angles before and after exposure to such solutions. The rock hardness of Marcellus samples was significantly affected by using both high and low pH solutions, which resulted in 55-94% loss of its initial value using low pH solutions and 50-68% when using high pH solutions.
- North America > United States > West Virginia (1.00)
- North America > United States > Pennsylvania (1.00)
- North America > United States > Ohio (1.00)
- North America > United States > New York (1.00)
- North America > United States > West Virginia > Appalachian Basin > Marcellus Shale Formation (0.99)
- North America > United States > Virginia > Appalachian Basin > Marcellus Shale Formation (0.99)
- North America > United States > Texas > West Gulf Coast Tertiary Basin > Eagle Ford Shale Formation (0.99)
- (40 more...)
- Reservoir Description and Dynamics > Unconventional and Complex Reservoirs > Shale gas (1.00)
- Reservoir Description and Dynamics > Reservoir Characterization > Exploration, development, structural geology (1.00)
- Reservoir Description and Dynamics > Improved and Enhanced Recovery (1.00)
- Reservoir Description and Dynamics > Formation Evaluation & Management (1.00)
Abstract Low salinity water flooding is gaining much of attention for its potential in increasing oil recovery, in spite of the debatable working mechanism for both sandstone (SS) and chalk. Various mechanisms have been suggested in literature. The objective of this work is to address oil/brine/rock (COBR) interaction and deduce thermodynamically possible product of the interaction, then verify with the experimental results. The experiments were designed to have most of the flooding with LSW as a secondary recovery method following seawater (SSW). This is to mimic the situation in most oil fields, which gone through seawater flooding and to contribute to the debatable discussion on the rule of LSW to enhance oil recovery as secondary or primary fluid. From previous work in our laboratory, sulfate and magnesium have been identified as active ions in the seawater in altering chalk wettability to more water wet; hence they were also tested as single ions water flooding and imbibing fluids for both SS and chalk. This approach has contributed to our understanding of the possible reactions that occurs due to COBR. From the SS part of the experiments, the results show indications of ion exchange, mineral dissolution processes and rock weakening causing fine migration. Mineral dissolution and ion exchange are not unexpected in presence of mineral such as, in general, kaolinite. The experimental results confirmed the simulated reaction between LSW and kaolinite from the increase of the pH and the resulted ions. In addition, the increase of the pressure drop detected during the flooding, could be related to the fine migration in addition to visual observation. From the work performed on chalk, the results indicate fine detachment, which was enhanced in presence of Mg ions as imbibing fluid at elevated temperature (70°C) for chalk. An increase of the pH was also observed for all flooding and spontaneous imbibition tests, especially with SO4 (for SS and chalk). In contrast to SS, chalk flooded with LSW showed reduction of pressure drop across the cores.
- North America > United States > Oklahoma (0.29)
- Europe > Norway > North Sea (0.28)
- Geology > Rock Type > Sedimentary Rock > Clastic Rock > Sandstone (0.75)
- Geology > Mineral > Silicate > Phyllosilicate (0.54)
- Geology > Rock Type > Sedimentary Rock > Carbonate Rock (0.46)
- Europe > Norway > North Sea > Central North Sea > Central Graben > PL 018 > Block 2/4 > Greater Ekofisk Field > Ekofisk Field > Tor Formation (0.99)
- Europe > Norway > North Sea > Central North Sea > Central Graben > PL 018 > Block 2/4 > Greater Ekofisk Field > Ekofisk Field > Ekofisk Formation (0.99)
Enhancing Well Stimulation with Improved Salt Tolerant Surfactant for Bakken Formation
Zhou, Jia (Texas Tech University) | Cutler, Jennifer (Texas Tech University) | Hughes, Baker (Texas Tech University) | Morsy, Samiha (Texas Tech University) | Morse, Aaron (Baker Hughes) | Sun, Hong (Baker Hughes) | Qu, Qi (Baker Hughes)
Abstract The Bakken formation is located in parts of Montana, North Dakota, and Saskatchewan, Cananda. North Dakota alone produces more than 700,000 barrels per day and still growing, which accounts for 11 percent of the domestic total crude oil production, while the oil recovery factor of 1% in Bakken is necessary to be improved to a higher level. Current practice involves fracture stimulation of the mature Upper and Lower Bakken Shales above and below the middle layer (pay zone in carbonate or siltstone). The fractures penetrate and connect natural fractures within the reservoirs and promote more efficient drainage of the oil. This situation suggests that a surfactant technology incorporating in the well stimulation fluids at low dosage can be a fit in Bakken formation to enhance oil recovery. If properly designed, such additives in the fracture fluids will penetrate into the highly oil-saturated matrix or natural fracture region and accelerate the extraction of the oil in place by rapid imbibition. Extracted oil can readily flow from the matrix into the propped fracture system. Another benefit of this surfactant technology is its engineered property to leave the matrix or natural fracture face water-wet to facilitate oil movement during production. This paper presents a study of a series of such stimulation fluid additives developed for enhanced oil recovery. Crude oil samples from the Bakken formation were analyzed for several properties pertinent to surfactant formulation including organic constituents, total acid number, and viscosity. Compatibility tests were carried out including surfactant/produced water interaction, emulsion tendency, and surfactant compatibility with proposed fracturing fluids. A spontaneous imbibition process was employed to mimic surfactant additives penetrating the tight matrix and microfractures to recover more hydrocarbons. The results show that more than one of these products improved recovery of Bakken crude oil by spontaneous imbibition. The best of these products is recommended for field application.
- North America > United States > South Dakota (1.00)
- North America > United States > North Dakota (1.00)
- North America > United States > Montana (1.00)
- North America > Canada > Saskatchewan (1.00)
- Research Report > New Finding (0.34)
- Research Report > Experimental Study (0.34)
- North America > United States > Texas > West Gulf Coast Tertiary Basin > Eagle Ford Shale Formation (0.99)
- North America > United States > Texas > Sabinas - Rio Grande Basin > Eagle Ford Shale Formation (0.99)
- North America > United States > Texas > Maverick Basin > Eagle Ford Shale Formation (0.99)
- (3 more...)
- Well Completion > Hydraulic Fracturing (1.00)
- Reservoir Description and Dynamics > Unconventional and Complex Reservoirs > Naturally-fractured reservoirs (1.00)
- Reservoir Description and Dynamics > Improved and Enhanced Recovery (1.00)
- Reservoir Description and Dynamics > Formation Evaluation & Management (1.00)
Experimental and Numerical Assessment of Chemical EOR in Oil-Wet Naturally-Fractured Reservoirs
Bourbiaux, Bernard (IFP Energies nouvelles) | Fourno, André (IFP Energies nouvelles) | Nguyen, Quang-Long (IFP Energies nouvelles) | Norrant, Françoise (IFP Energies nouvelles) | Robin, Michel (IFP Energies nouvelles) | Rosenberg, Elisabeth (IFP Energies nouvelles) | Argillier, Jean-François (IFP Energies nouvelles)
Copyright 2014, Society of Petroleum Engineers This paper was prepared for presentation at the SPE Improved Oil Recovery Symposium held in Tulsa, Oklahoma, USA, 12-16 April 2014. This paper was selected for presentation by an SPE program committee following review of information contained in an abstract submitted by the author(s). Contents of the paper have not been reviewed by the Society of Petroleum Engineers and are subject to correction by the author(s). The material does not necessarily reflect any position of the Society of Petroleum Engineers, its officers, or members. Electronic reproduction, distribution, or storage of any part of this paper without the written consent of the Society of Petroleum Engineers is prohibited. Permission to reproduce in print is restricted to an abstract of not more than 300 words; illustrations may not be copied. The abstract must contain conspicuous acknowledgment of SPE copyright. Abstract Among various ways to extend the lifetime of mature fields, chemical EOR processes have been subject of renewed interest in the recent years. Oil-wet fractured reservoirs represent a real challenge for chemical EOR as the matrix medium does not spontaneously imbibe the aqueous solvent of chemical additives. However, a wide variety of surfactants can now be considered for EOR, among which products that alter the matrix wettability. The present paper deals with that recovery strategy and compares it with other strategies based on viscous drive enhancement. Comparison is based on the physical and numerical interpretation of original representative experiments. The kinetics of spontaneous imbibition of chemical solutions in oil-wet limestone plugs and mini-plugs has been quantified thanks to X-ray CT-scanning and NMR measurements. Despite the small size of samples and the slowness of experiments, accurate recovery curves could be inferred from in-situ fluid saturation measurements. Scale effects were found quite consistent between mini-plugs and plugs. During a second experimental step, representative drive conditions of a fractured reservoir were imposed between the end-faces of a plug, in order to account for the possibly-significant contribution of fracture viscous drive to matrix oil recovery. These experiments were carefully analyzed and their numerical modeling was initiated with a simulation software that takes into account the multiple effects of surfactant presence on rock-fluids systems, including rock wettability modification and water-oil interfacial tension reduction.
- North America > United States > Texas (0.46)
- North America > United States > Oklahoma > Tulsa County > Tulsa (0.34)
- Energy > Oil & Gas > Upstream (1.00)
- Materials > Chemicals > Commodity Chemicals > Petrochemicals (0.48)
Abstract We present an experimental study on CO2-brine relative permeability in a Berea sandstone core at 1500 psi and 20 °C. Recently, there have been many experimental studies on CO2 relative permeability, but most of them determined the relative permeabilities only using the total pressure drop across a core sample; this pressure drop can be strongly affected by the capillary end effect, especially for a low viscosity fluid like CO2. In order to minimize the capillary end effect, we chose a long (61 cm) and low permeability (49 mD) core such that the capillary pressure in the core is negligible compared with the total pressure drop across the core. In addition, we used a core holder with four pressure taps that allow us to measure the pressure drops of the five continuous sections of the core. Capillary end effect was detected in our experimental results and was isolated to the most upstream and most downstream sections of the core. And the middle three sections are considered with minimized capillary end effect and the average of the relative permeabilities in middle three sections are taken as the best measurements. In summary, our experiments obtained a CO2 end point relative permeability of 0.4~0.8 and a brine end point relative permeability of 0.04~0.08, which are very similar to oil-brine end point relative permeabilities in water-wet sandstone.
- North America > United States > Texas (0.28)
- North America > United States > West Virginia (0.25)
- North America > United States > Pennsylvania (0.25)
- (2 more...)
- Research Report > New Finding (1.00)
- Research Report > Experimental Study (1.00)
Abstract The objective of this study is to develop strategies to improve oil recovery in highly fractured carbonate reservoirs at high temperatures (100°C and above). Such reservoirs usually contain high salinity and high hardness formation brines. The use of nonionic surfactants or anionic surfactants (Carboxylates and Sulfonates) to alter oil-wet reservoirs towards more water-wet was investigated under harsh reservoir conditions. A nonionic surfactant Ethomeen® T/25 has shown aqueous stability at high salinity and temperature with high effectiveness in wettability alteration and imbibition oil recovery. Anionic surfactant formulations were developed to recover oil mainly by gravity drainage since they did not show wettability alteration effect in hard brine. Both experimental and simulation studies have shown that sulfonate/carboxylate surfactants achieve high performance in wettability alteration and spontaneous imbibition only when they mix with chelating agents in formulations. Chelating agents, especially EDTA.4Na and sodium polyacrylate (NaPA) have been tested for their compatibility and effectiveness in the surfactant formulations. By sequestering divalent ions in hard brine, chelating agents free anionic surfactants to react at the solid-fluid interface to alter wettability of carbonates from oil-wet towards more water-wet. The chelating agents trigger mineral dissolution, but that does not lead to wettability alteration or contribute to the imbibition oil recovery directly.
- North America > United States > Texas (0.28)
- North America > United States > Oklahoma (0.28)
- Geology > Mineral (0.51)
- Geology > Geological Subdiscipline (0.34)
- Geology > Rock Type > Sedimentary Rock > Carbonate Rock > Dolomite (0.32)
- Energy > Oil & Gas > Upstream (1.00)
- Materials > Chemicals > Commodity Chemicals > Petrochemicals (0.46)
Evaluation of Surfactants for Oil Recovery Potential in Shale Reservoirs
Nguyen, Duy (Nalco Champion) | Wang, Dongmei (University of North Dakota) | Oladapo, Aderaje (Nalco Champion) | Zhang, Jin (University of North Dakota) | Sickorez, Jeffrey (Nalco Champion) | Butler, Ray (University of North Dakota) | Mueller, Brian (Nalco Champion)
Abstract Most shale reservoirs (e.g., Bakken Shale and Eagle Ford) have a low permeability, low porosity, and oil-wet character with natural fractures. As a result, the oil recovery factors are very low, only a few percent of original oil in place. Injection of water into oil-wet reservoirs (i.e., water flooding) is not effective due to small or negative capillary pressure. In this study, various surfactants (non-ionic, cationic, anionic, and amphoteric) were studied for spontaneous imbibition into oil-wet shale cores. Surfactant imbibition into Eagle Ford shale outcrop cores and Bakken reservoir cores increased oil recovery compared to brine only. Oil recovery can be seen for surfactants that alter the reservoir from oil-wet to water-wet. For example, the incremental oil recovery was about 24% % for 0.1% cationic surfactant and 57% for 0.1% nonionic surfactant. The goal of this work is to investigate the effect of salinity, surfactant concentration, electrolyte concentration, and temperature on the wettability alteration and provide mechanisms. Contact angles and interfacial tensions (IFT) were measured and correlated with spontaneous imbibition. Wettability alteration from oil-wet to water-wet (i.e., low contact angle) appeared to be more important than a low interfacial tension in increasing the oil recovery rate from fractured oil-wet reservoirs, especially for nonionic surfactants and amphoteric surfactants. Wettability alteration is maximum and IFT is minimum for anionic and cationic surfactants at an optimal salinity. However, as the reservoir salinity increases, the maximum wettability alteration decreases and IFT increases.
- Energy > Oil & Gas > Upstream (1.00)
- Materials > Chemicals > Commodity Chemicals > Petrochemicals (0.47)
- North America > United States > Texas > West Gulf Coast Tertiary Basin > Eagle Ford Shale Formation (0.99)
- North America > United States > Texas > Sabinas - Rio Grande Basin > Eagle Ford Shale Formation (0.99)
- North America > United States > Texas > Maverick Basin > Eagle Ford Shale Formation (0.99)
- (3 more...)
Abstract Results of Newtonian Fluids flooding very homogeneous porous media show that the Displacement Efficiency (ED) of a certain system is determined by the Capillary Number (Nc) of the driving fluid. The experience gained from Chemical Flooding natural cores and reservoirs that are all micro (pore scale) heterogeneous to some degree show that ED is influenced, besides Nc, by many other factors as explained below. Newtonian Fluids do not have elastic properties; emulsions and gas bubbles are not formed; when flooding, there is no change in the wettability of the system; there is no imbibition; and there is no alteration in the geometry of the pores. However, when chemical flooding, elasticity markedly effects the ED; emulsions and gas bubbles (especially when gas is injected) will often show up, which from core and field tests, could significantly increase the recovery; both w/o and o/w emulsions markedly change the phase permeability behavior and water cut; the wettability will often change and imbibition will occur; pore geometry alteration by solution and precipitation will happen, which influences the permeability, imbibition and recovery. The above factors all markedly influence the ED of the system, especially when many factors act jointly. From the above understanding, some directions on the development and selection of chemicals for EOR are put forward. The concept of ultimate ED and economic ED and its affect on the selection of actual field flooding systems is analyzed (many papers analyze ultimate ED, however, in the field, usually economical ED is more important). Besides Nc, the above factors should be considered when developing and selection chemicals and flooding systems. The above insights can further deepen our knowledge of the mechanism of chemical flooding, promote further research in this area and form better selection criteria for EOR chemicals and flooding systems in the field.
- North America (0.68)
- Asia > China > Heilongjiang Province (0.30)
- Asia > China > Heilongjiang > Songliao Basin > Daqing Field > Yian Formation (0.99)
- Asia > China > Heilongjiang > Songliao Basin > Daqing Field > Mingshui Formation (0.99)
- North America > United States > Louisiana > China Field (0.98)
Low Salinity EOR in Carbonates
Romanuka, J.. (Shell GSI BV) | Hofman, J. P. (Shell GSI BV) | Ligthelm, D. J. (Shell GSI BV) | Suijkerbuijk, B. M. (Shell GSI BV) | Marcelis, A. H. (Shell GSI BV) | Oedai, S.. (Shell GSI BV) | Brussee, N. J. (Shell GSI BV) | van der Linde, A.. (Shell GSI BV) | Aksulu, H.. (University of Stavanger) | Austad, T.. (University of Stavanger)
Abstract Modifying the chemistry of injection water yields improved wettability behavior on carbonate rock surfaces. Previous work has focused on demonstrating the effect of modified brine formulation on particular carbonate samples. Here the results of a more general screening study consisting of Amott spontaneous imbibition experiments on the samples from oil-bearing zones and from outcrops of different carbonate formations are reported. Tertiary incremental oil production due to increased water-wetness was observed upon transition to brine of lower ionic strength. Additional oil recovery from the spontaneous imbibition tests ranged from 4 to 20% of OIIP (Oil Initially In Place), reflecting a large variability in the response and indicating a high complexity of the mechanism(s). Consistent with numerous published reports, Stevns Klint outcrop chalk samples were a clear exception and exhibited increased oil recovery with increasing sulfate ion concentration. These did not respond to lowering the salinity of the imbibing brine. Tertiary oil recovery from samples containing evaporites occurred simultaneously with dissolution of salt minerals, as evident from brine analysis. However, incremental oil recovery in the same range was measured for samples without evaporites but from the same geological formation. Hence, mineral dissolution as a mechanism for enhanced oil recovery could not be confirmed. The results show that injection of low salinity brine into carbonate reservoirs has potential as an EOR technology. However, additional research is needed to improve the understanding of the underlying chemical and physical mechanisms and improve a priori predictability.
- Europe > Norway (0.88)
- North America > United States > Texas (0.46)
- Geology > Rock Type > Sedimentary Rock > Carbonate Rock (1.00)
- Geology > Mineral (1.00)
- Europe > Norway > North Sea > Central North Sea > Central Graben > PL 018 > Block 2/4 > Greater Ekofisk Field > Ekofisk Field > Tor Formation (0.99)
- Europe > Norway > North Sea > Central North Sea > Central Graben > PL 018 > Block 2/4 > Greater Ekofisk Field > Ekofisk Field > Ekofisk Formation (0.99)
Abstract For ultra-tight shale reservoirs, wettability strongly affects fluid flow behavior. However, wettability can be modified by numerous complex interactions and the ambient environment, such as pH, temperature, or surfactant access. In our previous study for Bakken shale imbibition, a group of surfactant formulations were examined—balancing the temperature, pH, salinity, and divalent cation content of aqueous fluids to increase oil production from shale with ultra-low porosity and permeability in the Middle Member of the Bakken Formation in the Williston Basin of North Dakota. To advance this work, this paper determines the wettability of different parts of the Bakken Formation. One goal of this research is to identify if the wettability can be altered using surfactant formulations. The ultimate objective of this research is to determine the potential of surfactant formulations to imbibe into and displace oil from shale, and examine the viability of a field application. Using modified Amott-Harvey tests, the wettability was determined for cores from three wells at different portions of the Bakken Formation. The tests were performed under reservoir conditions (90-120°C, 150-300 g/L formation water salinity) using Bakken crude oil. Both cleaned cores (cleaned by toluene/methanol) and untreated cores (sealed, native state) were investigated. Bakken shale cores were generally oil-wet or intermediate-wet (before introduction to the surfactant formulation). The four surfactant formulations that we tested consistently altered the wetting state of Bakken cores toward water-wet. These surfactants consistently imbibed to displace significantly more oil than brine alone. Four of the surfactant imbibition tests provided EOR values of 6.80% to 10.15% OOIP, incremental over brine imbibition. Ten surfactant imbibition tests provided EOR values of 15.65% to 25.40% OOIP. Thus, imbibition of surfactant formulations appears to have a substantial potential to improve oil recovery from the Bakken Formation. For comparison, recovery factors using the existing production methods are only on the order of a few percent OOIP. Positive results were generally observed with all four surfactants: 17A, 58N, S2, and C1. From our work to date, no definitive correlation is evident in surfactant effectiveness versus (1) temperature, (2) core porosity, (3) whether the core was from the Upper Shale or the Middle Member and (4) whether the core was preserved (sealed) or cleaned prior to use.
- North America > United States > South Dakota (1.00)
- North America > United States > North Dakota (1.00)
- North America > United States > Montana (1.00)
- Materials > Chemicals > Commodity Chemicals > Petrochemicals (1.00)
- Energy > Oil & Gas > Upstream (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)