The Green River, Utah holds the world's greatest oil shale resources. However, the hydrocarbon, which is namely kerogen, extraction from shales is limited due to environmental and technical challenges. In this study, we investigated the effectiveness of the combustion process for shale oil extraction. Samples collected from the Green River formation were first characterized by X-ray Diffraction (XRD) and Scanning Electron Microscopy (SEM). Then, series of dry combustion tests were conducted at different heating rates and wet combustion tests by water addition. The combustion efficiency was enhanced by mixing oil shale samples with an iron based catalyst. The effectiveness of dry, wet, and catalyst added combustion processes was examined by the thermal decomposition temperature of kerogen. Because the conventional oil shale extraction methods are pyrolysis (retorting) and steaming, the same experiments were conducted also under nitrogen injection to mimic retorting. It has been observed that the combustion process is a more efficient method for the extraction of kerogen from oil shale than the conventional techniques. The addition of water and catalyst to combustion has been found to lower the required temperature for kerogen decomposition for lower heating rate. This study provides insight for the optimization of the thermal methods for the kerogen extraction.
Fracturing fluids are commonly formulated with fresh water to ensure reliable rheology. However, fresh water is becoming more costly, and in some areas, it is difficult to obtain. Therefore, using produced water in hydraulic fracturing has received increased attention in the last few years. A major challenge, however, is its high total dissolved solids (TDS) content, which could cause formation damage and negatively affect fracturing fluid rheology. The objective of this study is to investigate the feasibility of using produced water to formulate crosslinked-gel-based fracturing fluid. This paper focuses on the compatibility of water with the fracturing fluid system and the effect of salts on the fluid rheology.
Produced water samples were analyzed to determine different ion concentrations. Solutions of synthetic water with different amounts of salts were prepared. The fracturing fluid system consisted of natural guar polymer, borate-based crosslinker, biocide, surfactant, clay controller, scale inhibitor, and pH buffer. Compatibility tests of the fluid system were conducted at different cation concentrations. Apparent viscosity of the fracturing fluid was measured using a high-pressure high-temperature rotational rheometer. All rheology tests were conducted at a temperature of 180°F and were conducted according to API 13m procedure with a three-hour test duration. Fluid breaking test was also performed to ensure high fracture and proppant pack conductivity.
Produced water analysis showed a TDS content of 125,000 ppm, including Na, Ca, K, and Mg ion concentrations of 36,000, 10,500, 1,700, and 700 ppm, respectively. Results indicated the potential of produced water to cause formation damage. Therefore, produced water was diluted with fresh water and directly used to formulate the fracturing fluid. Divalent cations were found to be the main source of precipitation, and the reduced amounts of each ion were determined to prevent precipitation. The separate and combined effects of Na, K, Ca, and Mg ions on the viscosity of the fracturing fluid were also studied. Fluid viscosity was found to be significantly affected by the concentrations of divalent cations regardless of the concentrations of monovalent cations. Monovalent cations reduced the viscosity of fracturing fluid only in the absence of divalent cations, and showed no effect in the presence of Ca and Mg ions. Water with reduced concentrations of monovalent and divalent cations showed the most suitable environment for polymer hydration and crosslinking.
This paper contributes to the understanding of the main factors that enable the use of produced water for hydraulic fracturing operations. Maximizing the use of produced water could reduce its disposal costs, mitigate environmental impacts, and solve fresh water acquisition challenges.
Preliminary studies have been done to characterize rock-fluid properties, and flow mechanisms in the shale reservoirs. Most of these studies, through modifying methods used for conventional reservoirs, fail to capture dynamic features of shale rock and fluids in confined nano-pore space. In unconventional reservoirs, interactions between the wall of shale and the contained fluid significantly affect phase and flow behaviors. The inability to model capillarity with the consideration of pore size distribution characteristics using commercial software may lead to an inaccurate oil production performance in Bakken. This paper presents a novel formulation that consistently evaluates capillary force and adsorption using pore size distribution (PSD) directly from core measurements. The new findings could better address differences in flow mechanisms in unconventional reservoirs, and thus lead to an optimized IOR practice.
Once a shale gas condensate reservoir is produced, the reservoir pressure falls below the dew-point pressure, and the condensate liquid will be formed in the pore space; the condensate can then accumulate near the wellbore. This condensate blockage would reduce the gas relative permeability and decrease the gas production. The condensate is formed by the heavy components in reservoir fluid, and these heavy componenets are very valuable economically in the industry. Therefore, operators are seeking ways to maximize condensate recovery from gas-condensate reservoirs.
Huff-n-puff gas injection is an effective approach for enhancing condensate recovery in shale gas condensate reservoirs, as shown by our earlier papers (
In this experimental study, a binary gas condensate mixture was used to investigate the dominant mechanism. The core was saturated with a gas condensate mixture at 2200 psi to simulate the initial reservoir condition. Then, the pressure was depleted to 1500 psi, which was lower than the dew point pressure. During the depletion, the produced gas was collected in a vacuumed gas sample bag. After depletion, the huff-n-puff method was applied. After every cycle of huff-n-puff, the produced gas was collected. GC was used to analyze the compositions of the different gas samples. Also, a CT scanner was used to determine the condensate saturation in the core. From the GC analysis, by comparing the gas sample after primary depletion with the gas sample after the first cycle, it was found that the heavy component-butane increased significantly. This means that most of the heavy components of condensate were revaporized and flew out with the dry gas. This proves the revaporization mechanism of the huff-n-puff gas injection.
Our experiment results show that huff-n-puff was an effective way to enhance the condensate recovery, and revaporization was the main mechanism of huff-n-puff. When the pressure was increased in the huff process, the heavy components were revaporized and flowed out with gas in the puff process. Though in the gas flooding method, the reservoir pressure was also increased, but the near-wellbore pressure was not increased very much in the shale gas reservoirs; thus, heavy components would still be formed near the wellbore. However, in the huff-n-puff method, because of the same well, the pressure near the wellbore would be higher than the dew point pressure in the beginning of production process. Therefore, the heavy component would be recovered with gas. Our GC results visually showed the revaporization mechanism of huff-n-puff in the shale gas condensate.
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.
The importance of tuning injection water chemistry for upstream is getting beyond formation damage control/water incompatibility to increase oil recovery from waterflooding and different improved oil recovery (IOR)/enhanced oil recovery (EOR) processes. The water chemistry requirements for IOR/EOR have been relatively addressed in the recent literature, but the key challenge for field implementation is to find an easy, practical, and optimum technology to tune water chemistry. The currently available technologies for tuning water chemistry are limited, and most of the existing ones are adopted from the desalination industry, which relies on membrane based separation. Even though these technologies yield a doable solution, they are not the optimum choice to alter injection water chemistry in terms of incorporating selective ions and providing effective water management for large scale applications. In this study, several of the current, emerging, and future desalination technologies are reviewed with an objective to develop potential water treatment solutions that can most efficiently alter injection water chemistry for SmartWater flooding in carbonate reservoirs.
Standard chemical precipitation technologies, such as lime/soda ash, alkali, and lime/aluminum based reagent, are only applicable for removing certain ions from seawater. The lime/aluminum based reagent process looks interesting, as it can remove both sulfates and hardness ions to provide some tuning flexibility for key ions included in the SmartWater. There are some new technologies under development that use chemical solvents to extract salt ions from seawater, but their capabilities to selectively remove specific ions need further investigation.
Forward osmosis and membrane distillation are the two emerging technologies, and these can provide good alternatives to reverse osmosis seawater desalination for the near-term. These technologies can offer a better cost-effective solution where there is availability of low grade waste heat or steam. The two new desalination technologies, based on dynamic vapor recovery and carrier gas extraction, are well suited to treat high salinity produced water for zero liquid discharge (ZLD). These technologies may not be able to provide an economical solution for seawater desalination. Carbon nanotube desalination, graphene sheet-based desalination, and capacitive deionization are the three potential future seawater desalination technologies identified for the long term. Among these, carbon nanotube based desalination is much attractive, although the technology is still largely under research and development.
This review study results show that there is no commercial technology yet available to selectively remove specific ions from seawater in one step and optimally meet desired water chemistry requirements of SmartWater flooding. As a result, different novel schemes involving selected combinations of chemical precipitation, conventional/emerging desalination, and produced water treatment technologies are proposed. These schemes represent both approximate and improved solutions to selectively incorporate specific key ions in the SmartWater, besides presenting the key opportunities to treat produced water/membrane rejects and provide ZLD capabilities in SmartWater flooding applications. The developed novel schemes can provide an attractive solution to capitalize on existing huge produced water resources in Saudi reservoirs to generate SmartWater and minimize wastewater disposal during field-wide implementation.
San, Jingshan (New Mexico Institute of Mining and Technology) | Wang, Sai (New Mexico Institute of Mining and Technology) | Yu, Jianjia (New Mexico Institute of Mining and Technology) | Lee, Robert (New Mexico Institute of Mining and Technology) | Liu, Ning (New Mexico Institute of Mining and Technology)
This paper reports the study of the effect of different ions (monovalent, bivalent, and multiple ions) on nanosilica-stabilized CO2 foam generation. CO2 foam was generated by co-injecting CO2/5,000 ppm nanosilica dispersion (dispersed in different concentrations of brine) into a sandstone core under 1,500 psi and room temperature. A sapphire observation cell was used to determine the foam texture and foam stability. Pressure drop across the core was measured to estimate the foam mobility. The results indicated that more CO2 foam was generated as the NaCl concentration increased from 1.0% to 10%. Also the foam texture became denser and foam stability improved with the NaCl concentration increase. The CO2 foam mobility decreased from 13.1 md/cp to 2.6 md/cp when the NaCl concentration increased from 1% to 10%. For the bivalent ions, the generated CO2 foam mobility decreased from 19.7 md/cp to 4.8 md/cp when CaCl2 concentration increased from 0.1% to 1.0%. Synthetic produced water with total dissolved solids of 17,835 ppm was prepared to investigate the effect of multiple ions on foam generation. The results showed that dense, stable CO2 foam was generated as the synthetic produced water and nanosilica dispersion/CO2 flowed through a porous medium. The lifetime of the foam was observed to be more than two days as the foam stood at room temperature. Mobility of the foam was calculated as 5.2 md/cp.
The polymer pilot project performed in the 8 TH reservoir of the Matzen field showed encouraging incremental oil production. To further improve the understanding of recovery effects resulting from polymer injection, an extension of the pilot is planned by adding a second polymer injector.
Forecasting of the incremental oil production needs to take the uncertainty of the geological models and dynamic parameters into account. We propose a workflow which comprises a geological sensitivity and clustering step followed by a dynamic calibration step for decreasing the objective function to improve the reliability of a probabilistic forecast of the incremental oil recovery.
For the geological sensitivity, hundreds of geological realizations were generated taking the uncertainty in the correlation of the sand and shale layers, logs, cores and geological facies into account. The simulated tracer response was used as dissimilarity distance to classify the geological realizations. Clustering was then applied to select 70 representative realizations (centroids) from a total of 800 to use in the full-physics dynamic simulation.
In the dynamic simulation, an objective function comprising liquid rate and tracer concentration of the back-produced fluids was introduced.
To further improve the calibration, the P50 value of incremental oil production as derived from simulation was compared with the incremental oil production determined from Decline Curve Analysis from the wells surrounding the polymer injection well. The mismatch between the P50 and the Decline Curve Analysis was improved by adjusting polymer viscosity.
The calibrated models were then used to for a probabilistic forecast of incremental oil due to an additional polymer injector and to estimate the expected polymer concentration at the producing wells.
Improved Oil Reocvery (IOR) technologies may offer a new strategy to improve the initial production (IP) and slow the production decline from oil-rich shale formations. Early implementation of chemical IOR technologies largely have been overlooked during strategic planning of unconventional reservoirs. The purpose of this study is to improve understanding of the dynamic processes of oil displacement by surfactants and to investigate mechanism of how surfactants extract oil. A successful conventional surfactant "huff-n-puff' treatment is described with a focus on any relationship between increased oil production and the surfactant soaking period. Surfactant chemistry has been considered as one of a few ultimate IOR solutions. Despite being well proven as effective chemicals to recover oil from convenetional reservoris, surfactants commonly are used in hydraulic fracturing of unconventional reservoris are just to promote flow back of the injected aqueous fluid over a relatively short time frame. In order to better understand the functionality of surfactants for obtaining favorable oil interaction with both the stimulation fluid and rock matrix, a specifically-designed "oil-on-a-plate" (OOAP) setup and procedure is employed to examine the penetration of surfactant into the oil-film that is adhereing to a solid surface. In addition to the well-recognized spontaneous imbibition and surface wettability alternation processes, surfactant also can gradually penetrate and mobilize oil droplets, resulting in improved oil recovert. If properly selected and designed, the surfactant additives in stimulation/fracturing fluids could have multi-functions towards improving both IP and the longer-term oil production. Besides serving as a demulsifier and flowback enhancer to boost IP, the surfactants could continuously lift-up and mobilize adsorbed oil to increase recoverable oil in place.
This paper summarizes the current state of the ethane industry in the United States and explores the opportunity for using ethane for enhanced oil recovery. We show both simulation data and field examples to demonstrate that ethane is an excellent EOR injectant.
After decades of research and field application, the use of CO2 as an EOR injectant has proven to be very successful. However, there are limited supplies of low cost CO2 available, and there are also significant drawbacks, especially corrosion, involving its use. The rich gasses and volatile oils developed by horizontal drilling and fracturing in the shale reservoirs have brought about an enormous increase in ethane production. Ethane prices have dropped substantially. In the U.S., ethane is no longer priced as a petrochemical feedstock, but is priced as fuel. Also, substantial quantities of ethane are currently being flared.
Ethane-based EOR can supplement the very successful CO2-based EOR industry in the U.S. There simply isn't enough low-cost CO2 available to undertake all of the potential gas EOR projects in the U.S. The current abundance of low-cost ethane presents a significant opportunity to add new gas EOR projects. The ethane-based EOR opportunity can be summarized as follows; CO2-based EOR works well, and is well understood. Ethane is better than CO2 for EOR. Ethane is simpler than CO2 for EOR. Ethane is now inexpensive, and will likely stay inexpensive. Ethane-based EOR has become a viable option in the Lower 48. Large volumes of low-cost ethane are available. Recent additions to the growing ethane infrastructure now deliver ethane to locations where ethane-based EOR targets are plentiful.
CO2-based EOR works well, and is well understood.
Ethane is better than CO2 for EOR.
Ethane is simpler than CO2 for EOR.
Ethane is now inexpensive, and will likely stay inexpensive.
Ethane-based EOR has become a viable option in the Lower 48. Large volumes of low-cost ethane are available. Recent additions to the growing ethane infrastructure now deliver ethane to locations where ethane-based EOR targets are plentiful.