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Liang, Feng (Aramco Services Company: Aramco Research Center—Houston) | Han, Yanhui (Aramco Services Company: Aramco Research Center—Houston) | Liu, Hui-Hai (Aramco Services Company: Aramco Research Center—Houston) | Saini, Rajesh (Aramco Services Company: Aramco Research Center—Houston) | Rueda, Jose I. (Saudi Aramco)
Summary Hydraulic fracturing has been widely used in stimulating tight carbonate reservoirs to improve oil and gas production. Improving and maintaining the connectivity between the natural and induced microfractures in the far‐field and the primary fracture networks are essential to enhancing the well production rate because these natural and induced unpropped microfractures tend to close after the release of hydraulic pressure during production. This paper provides a conceptual approach for an improved hydraulic fracturing treatment to enhance the well productivity by minimizing the closure of the microfractures in tight carbonate reservoirs and enlarging the fracture aperture. The proposed improved fracturing treatment was to use the mixture of the delayed acid‐generating materials along with microproppants in the pad/prepad fluids during the engineering process. The microproppants were used to support the opening of natural or newly induced microfractures. The delayed acid‐generating materials were used in this strategy to enlarge the flow pathways within microfractures owing to degradation introduced under elevated temperatures and interaction with the calcite formation. The feasibility of the proposed approach is evaluated by a series of the proof‐of‐concept laboratory coreflood experiments and numerical modeling results. First, one series of experiments (Experiments 1–3) was designed to investigate the depth of the voids on the fracture surface generated by the solid delayed acid‐generating materials under different flow rates of the treatment fluids and different temperatures. This set of tests was conducted on a core plug assembly that was composed of half-core Eagle Ford Sample, half-core hastelloy core plug, and a mixture of solid delayed acid‐generating materials [polyglycolic acid (PGA)] along with small‐sized proppants sandwiched by two half‐cores. Surface profilometer was used to quantify the surface‐etched profile before and after coreflood experiments. Test results have shown that PGA materials were able to create voids or dimples on the fracture faces by their degradation under elevated temperature and the chemical reaction between the generated weak acid and the calcite‐rich formation. The depth of the voids generated is related to the treatment temperature and the flow rate of the treatment fluids. Experiment 4 was conducted using two half‐core splits to quantify the improvement factor of the core permeability due to the treatment with mixed sand and PGA materials. Simulations of fluid flow through proppant assembly (inside of the microfractures) using the discrete element method (DEM)–lattice Boltzmann method (LBM) coupling approach for three different scenarios (14 cases in total) were further conducted to evaluate the fracture permeability and conductivity changes under different situations such as various gaps between proppant particulates and different depths of voids generated on fracture faces: (1) fluid flow in a microfracture without proppant, (2) fluid flow in a microfracture with small‐sized proppants, and (3) fluid flow in a microfracture supported by small‐sized proppants and generated voids on the fracture walls. The simulation results show that with proppant support (Scenario 2), the microfracture permeability can be increased by tens to hundreds of times in comparison to Scenario 1, depending on the gaps between proppant particles. The permeability of proppant‐supported microfracture (Scenario 3) can be further enhanced by the cavities created by the reactions between the generated acid and calcite formation. This work provides experimental evidence that using the mixture of the solid delayed acid‐generating materials along with microproppants or small‐sized proppants in stimulating tight carbonate reservoirs in the pad/prepad fluids during the engineering process may be able to effectively improve and sustain permeability of flow pathways from microfractures (either natural or induced). These findings will be beneficial to the development of an improved hydraulic fracturing treatment for stimulating tight organic‐rich carbonate reservoirs.
Summary Hydraulic fracturing has been widely used for unconventional reservoirs, including organic‐rich carbonate formations, for oil and gas production. During hydraulic fracturing, massive amounts of fracturing fluids are pumped to crack open the formation, and only a small percentage of the fluids are recovered during the flowback process. The negative effects of the remaining fluid on the formation, such as clay swelling and reduction of rock mechanical properties, have been reported in the literature. However, the effects of the fluids on source‐rock properties—especially on microstructures, porosity, and permeability—are scarcely documented. In this study, microstructure and mineralogy changes induced in tight carbonate rocks by imbibed fluids and the corresponding changes in permeability and porosity are reported. Two sets of tight organic‐rich carbonate‐source‐rock samples were examined. One sample set was sourced from a Middle East field, and the other was an outcrop from Eagle Ford Shale that is considered to be similar to the one from the Middle East field in terms of mineralogy and organic content. Three fracturing fluids—2% potassium chloride (KCl), 0.5 gal/1,000 gal (gpt) slickwater, and synthetic seawater—were used to treat the thin section of the source‐rock and core samples. Modern analytical techniques, such as scanning electron microscopy (SEM) and energy‐dispersive spectroscopy (EDS), were used to investigate the source‐rock morphology and mineralogy changes before and after the fluid treatment, at the micrometer scale. Permeability as a function of effective stress was quantified on core samples to investigate changes in flow properties caused by the fracturing‐fluid treatments. The SEM and EDS results before and after fracturing‐fluid treatments on the source‐rock samples showed the microstructural changes for all three fluids. For 2% KCl and slickwater fluid, reopening of some mineral‐filled natural fractures was observed. The enlargement of the aperture for pre‐existing microfractures was slightly more noticeable for samples treated with 2% KCl compared with slickwater at the micrometer scale. In one sample, dissolution of organic matter was captured in the slickwater‐fluid‐treated rock sample. Mineral precipitation of sodium chloride (NaCl) and generation of new microfractures were observed for samples treated with synthetic seawater. The formation of new microfractures and the dissolution of minerals could result in increases in both porosity and permeability, whereas the mineral deposition would result in permeability decrease. The overall increase in absolute gas permeability was quantified by the experimental measurements under different effective stress for the core‐plug samples. This effect on absolute‐gas‐permeability increase might have an important implication for hydrocarbon recovery from unconventional reservoirs. This study provides experimental evidence at different scales that aqueous‐based fracturing fluid might potentially have a positive effect on gas production from organic‐rich carbonate source rock by increasing absolute gas permeability through mineral dissolution and generation of new fractures or reopening of existing microfractures. This observation will be beneficial to the future use of freshwater‐ and seawater‐based fluids in stimulating gas production from organic‐rich carbonate formations.
Liang, Feng (Aramco Services Company: Aramco Research Center—Houston) | Zhang, Jilin (Aramco Services Company: Aramco Research Center—Houston) | Liu, Hui-Hai (Aramco Services Company: Aramco Research Center—Houston) | Bartko, Kirk M. (Saudi Aramco)
Abstract Hydraulic fracturing has been widely used for unconventional reservoirs including organic-rich carbonate formations for oil and gas production. During hydraulic fracturing, massive amount of fracturing fluids are pumped to crack-open the formation and only a small percentage of the fluid is recovered during the flowback process. The negative effects of the remaining fluid on the formation such as clays swelling and reduction of rock mechanical properties have been reported in literatures. However, effects of fluids on source rock properties, especially the microstructures, porosity and permeability, are scarcely documented. In this study, microstructure and mineralogy changes induced in tight carbonate rocks by imbibed fluids and corresponding changes in permeability and porosity are reported. Two sets of tight organic-rich carbonate source rock samples were examined. One sample set was sourced from the Middle East field and the other was an outcrop from Eagle Ford Shale that is considered to be analogous to the one from the Middle East field. Three fracturing fluids, namely 2% KCl, 0.5 gpt slickwater and synthetic seawater, were used to treat the thin-section of the source rock and core samples. Modern analytical techniques such as SEM and EDS were used to investigate the source-rock morphology and mineralogy changes prior and after the fluid treatment at micron-scale level. Porosity and permeability as a function of confining pressures were quantified on core samples to investigate changes in flow properties due to the fracturing fluids treatments. The SEM and EDS results prior to and after fracturing fluid treatments on the source rock samples showed the microstructural changes in all three fluids. In 2% KCl and slickwater fluid, reopening of some mineral-filled natural fractures was observed. The enlargement of micro-fractures was slightly more noticeable for samples treated with 2% KCl in comparison to slickwater at the micron-scale level. In one sample, dissolution of organic matters was captured in slickwater fluid treated rock sample. Some mineral precipitation and new micro-fractures generation were observed for samples treated with seawater. The new micro-fractures generation and mineral dissolution through the fluid treatment would result in the increases in both porosity and permeability, while the mineral deposition would result in permeability decrease. The overall increase in absolute gas permeability was quantified by the experimental measurements under different effective stresses for the core plug samples. This effect on absolute gas permeability increase has an important implication for hydrocarbon recovery from unconventional reservoirs. This study provides experimental evidences at different scales that aqueous-based fracturing fluid may potentially have positive effect on gas production from organic-rich carbonate source rock by increasing absolute gas permeability through mineral dissolution and generation of new or re-opening of old micro- fractures. This observation will be beneficial to the future usage of fresh and seawater based fluids in stimulating gas production for organic-rich carbonate formations.
Liang, Feng (Aramco Services Company: Aramco Research Center–Houston) | Al-Muntasheri, Ghaithan (Saudi Aramco) | Ow, Hooisweng (Aramco Services Company: Aramco Research Center–Boston) | Cox, Jason (Aramco Services Company: Aramco Research Center–Boston)
Summary In the quest to discover more natural-gas resources, considerable attention has been devoted to finding and extracting gas locked within tight formations with permeability in the nano- to microdarcy range. The main challenges associated with working in such formations are the intrinsically high-temperature and high-pressure bottom conditions. For formations with bottomhole temperatures at approximately 350–400°F, traditional hydraulic-fracturing fluids that use crosslinked polysaccharide gels, such as guar and its derivatives, are not suitable because of significant polymer breakdown in this temperature range. Fracturing fluids that can work at these temperatures require thermally stable synthetic polymers such as acrylamide-based polymers. However, such polymers have to be used at very-high concentrations to suspend proppants. The high-polymer concentrations make it very difficult to completely degrade at the end of a fracturing operation. As a consequence, formation damage by polymer residue can reduce formation conductivity to gas flow. This paper addresses the shortcomings of the current state-of-the-art high-temperature fracturing fluids and focuses on developing a less-damaging, high-temperature-stable fluid that can be used at temperatures up to 400°F. A laboratory study was conducted with this novel system, which comprises a synthetic acrylamide-based copolymer gelling agent and is capable of being crosslinked with an amine-containing polymer-coated nanosized particulate crosslinker (nanocrosslinker). The laboratory data have demonstrated that the temperature stability of the crosslinked fluid is much better than that of a similar fluid lacking the nanocrosslinker. The nanocrosslinker allows the novel fluid system to operate at significantly lower polymer concentrations (25–45 lbm/1,000 gal) compared with current commercial fluid systems (50–87 lbm/1,000 gal) designed for temperatures from 350 to 400°F. This paper presents results from rheological studies that demonstrate superior crosslinking performance and thermal stability in this temperature range. This fracturing-fluid system has sufficient proppant-carrying viscosity, and allows for efficient cleanup by use of an oxidizer-type breaker. Low polymer loading and little or no polymer residue are anticipated to facilitate efficient cleanup, reduced formation damage, better fluid conductivity, and enhanced production rates. Laboratory results from proppant-pack regained-conductivity tests are also presented.
Abstract Many fracturing fluids are based on guar and guar derivatives, primarily because of their abundance and capability to operate at relatively high temperatures when formulated at high pH. However, insoluble residue in guar can damage permeability especially in unconventional formations. Another issue for applying guar-based fluids at high pH is the tendency to form scales with divalent ions. The fluid cost can also be strongly influenced by the volatility of the guar price. A third disadvantage is their low thermal stability when the temperature exceeds around 350 ° F. To mitigate these operating issues, a low- or non-damaging, high-temperature fluid system without elevated fluid pH is therefore highly desirable. Thermally stable synthetic polymers such as acrylamide-based polymers and copolymers are considered to be low-residue to residue-free. However, acrylamide polymers at high doses may still cause formation damage in circumstances like incomplete degradation. This paper demonstrates the successful application of a specific acrylamide copolymer to formulate a novel low-loading, non-damaging fracturing fluid system that fulfilled high viscosity requirements over a temperature range from 280 to 450°F. The fracturing fluid system based on the novel acrylamide copolymer demonstrated superior viscosity performance and excellent thermal stability at high temperatures at 450°F or higher. In one example, at the polymer loading as low as 20 lbm/1,000 gallons, the fluid viscosity stayed above 500cP (at 40 s shear rate) at 300°F for about 2.5 hours. In another example, at a polymer loading of 30 pptg, the fluid viscosity stayed above 500cP (at 40 s shear rate) at 400°F for about 1.5 hours. This data indicates that the fluid system has sufficient proppant suspension capability. The fluids could be efficiently broken to allow for good cleanup using oxidative breakers. Proppant-pack conductivity tests showed good regained permeability of over 90% at 300°F, proving the low- to non-damaging potential of the fluid system to formations treated. Moreover, the low-loading fluid system also reduced the fluid cost by about 50% when compared with the commercially available systems with similar viscosity performance. Using the novel low-loading, residue-free acrylamide copolymer has therefore rendered better cleanup, reduced formation damage, lowered operating cost, and enhanced production rates. The fracturing fluid system based on the novel acrylamide copolymer has demonstrated the unprecedented combination of a number of advantages including low polymer loading, robust high-temperature performance, high regained permeability, low scaling tendency, and reduced operating cost.