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Collaborating Authors
Maverick Basin
Practical Optimization of Perforation Design with a General Correlation for Proppant and Slurry Transport from the Wellbore
Dontsov, Egor (ResFrac Corporation, Palo Alto, CA, USA) | Ponners, Christopher (ResFrac Corporation, Palo Alto, CA, USA) | Torbert, Kevin (Cornerstone Engineering, Inc., Bakersfield, CA, USA) | McClure, Mark (ResFrac Corporation, Palo Alto, CA, USA)
Abstract During plug and perf completion, perforation pressure drop is used to encourage a uniform distribution of flow between clusters by overcoming stress shadowing, stress variability, and nonuniform breakdown pressure. However, proppant inertia, gravitational settling, and perforation erosion contribute to nonuniformity, even with an aggressive limited-entry design. In prior work, Dontsov (2023) developed a correlation for predicting proppant outflow from the wellbore as a function of slurry velocity, perforation phasing, and other parameters. In the present study, the Dontsov (2023) correlation is integrated into a wellbore dynamics simulator capturing key physical processes that control slurry and proppant outflow from the wellbore, such as erosion, stress shadowing, and near-wellbore tortuosity. The simulator is fast running and incorporated into a tool for Monte Carlo uncertainty quantification and design optimization. First, we run a series of sensitivity analysis simulations to evaluate the effect of key model inputs. The simulations demonstrate processes that can cause heel bias, toe bias, or heel/toe bias in the erosion distribution. Next, we apply the tool to analyze field datasets from the Eagle Ford and the Montney. Downhole imaging of erosion data enables model calibration. Calibration is necessary because differences in casing, cement, and formation properties cause differences in erosion behavior and flow distribution. Parameters controlling the magnitude of erosion and stress shadow are modified to match the trends observed from the downhole imaging. After calibration is performed, the model is applied to maximize the uniformity of proppant placement by optimizing perforation phasing, diameter, count, and cluster spacing.
- Geophysics > Seismic Surveying > Borehole Seismic Surveying (0.55)
- Geophysics > Borehole Geophysics (0.55)
- 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)
- (26 more...)
_ The development of efficient technologies for drilling and hydraulically fracturing horizontal wells has enabled the US to more than double hydrocarbon production since 2005 (Fig. 1), thereby providing unprecedented levels of energy security for America. Americaโs doubling of hydrocarbon output has also held down the price of energy worldwide, and by doing so, accelerated global economic growth. And it has helped reduce the greenhouse gas (GHG) intensity of energy production by backing out โdirtierโ forms of energy, such as coal. Energy securityโeconomic growthโreduced GHGs vented to the atmosphere: Thatโs a winning combination. One that America and many other countries have benefitted from immensely. Given the enormous positive contributions, it is worth noting that 20 years ago, few if any in our industry foresaw the immense potential of this technology, seeing it as being only applicable for extracting gas from ultratight reservoirs like the Barnett Shale, if they were aware of the technology at all. This oversight caused many companies to wait too long before deciding to pursue unconventional reservoirs and caused several of the โshale gasโ pioneers to be late in recognizing that hydraulically fractured horizontal wells (HFHWs) could also be successfully applied in liquid-rich plays such as the Eagle Ford and Permian Basin. These are plays that today deliver far more value than that derived from the gas-prone reservoirs that comprised the initial suite of targets. And while events have proven beyond a doubt that HFHWs are a powerful tool for economically extracting hydrocarbons from both gas-prone and liquids-rich unconventional reservoirs, it seems likely that many in our industry are overlooking a third significant application of this technology: The use of HFHWs to extract heat from the Earthโs crust that can be utilized to generate electricity. Old Story, New Horizon What makes this third application particularly compelling as an investment opportunity is that the primary physical challenge that needs to be overcome to achieve attractive rates of return is strikingly similar to that which the oil and gas industry had to surmount to make both gas and liquids-rich unconventional reservoirs economic. The key to success in all of these cases boils down to an ability to create via hydraulic stimulation a sufficiently large amount of conductive, connected, fracture surface area. With this, one can reliably expect per-well production rates to be economic given the extremely slow rate at which hydrocarbonsโand heatโmove through unconventional reservoirs and the hot, dry, basement rocks that contain the bulk of the worldโs geothermal resources. That converting from vertical to horizontal well geometries was critical for unlocking the potential of unconventional hydrocarbon reservoirs is now obvious, with this switch having allowed petroleum engineers to increase per-well fracture surface areas by several orders of magnitude. This move increased per-well flow rates by similar amounts (i.e., from subeconomic flow rates from hydraulically fractured vertical wells (HFVWs) to flow rates of thousands of BOE/D from HFHWs.
- Energy > Oil & Gas > Upstream (1.00)
- Government > Regional Government > North America Government > United States Government (0.48)
- Energy > Renewable > Geothermal > Geothermal Resource (0.35)
- North America > United States > Texas > Fort Worth Basin > Barnett Shale Formation (0.99)
- North America > United States > Texas > West Gulf Coast Tertiary Basin > Eagle Ford Shale Formation (0.89)
- North America > United States > Texas > Sabinas - Rio Grande Basin > Eagle Ford Shale Formation (0.89)
- (25 more...)
The development of efficient technologies for drilling and hydraulically fracturing horizontal wells has enabled the US to more than double hydrocarbon production since 2005 (Figure 1), thereby providing unprecedented levels of energy security for America. America's doubling of hydrocarbon output has also held down the price of energy worldwide, and by doing so, accelerated global economic growth. And it has helped reduce the greenhouse gas (GHG) intensity of energy production by backing out "dirtier" forms of energy, such as coal. Energy security--economic growth--reduced GHGs vented to the atmosphere: That's a winning combination. One that America and many other countries have benefitted from immensely. Given the enormous positive contributions, it is worth noting that 20 years ago, few if any in our industry foresaw the immense potential of this technology, seeing it as being only applicable for extracting gas from ultratight reservoirs like the Barnett Shale, if they were aware of the technology at all.
- Energy > Oil & Gas > Upstream (1.00)
- Government > Regional Government > North America Government > United States Government (0.48)
- North America > United States > Texas > Fort Worth Basin > Barnett Shale Formation (0.99)
- North America > United States > Texas > West Gulf Coast Tertiary Basin > Eagle Ford Shale Formation (0.89)
- North America > United States > Texas > Sabinas - Rio Grande Basin > Eagle Ford Shale Formation (0.89)
- (25 more...)
The Lower Silurian Longmaxi rapid-transgressive black shale and organic matter distribution on the Upper Yangtze Platform, China
Shi, Zhensheng (PetroChina Research Institute of Petroleum Exploration and Development) | Zhou, Tianqi (PetroChina Research Institute of Petroleum Exploration and Development) | Qi, Ling (PetroChina Research Institute of Petroleum Exploration and Development)
Abstract The characteristics and formation of maximum flooding (MF) black shales are important aspects in defining the geology of fine-grained reservoirs. The MF black shales are located at the bottom of the Longmaxi Formation on the Upper Yangtze Platform, corresponding to graptolite zone LM1. Seismic interpretation, X-ray diffraction entire rock analysis, total organic carbon (TOC) tests, and field emission scanning electron microscopy analysis indicate that the MF black shales have an average content of 49.3% quartz (85% clay size), 10.5% calcite, 8.4% dolomite, and 23.4% clay minerals. The quartz content increases basinward, whereas the clay mineral content decreases. The shale has developed during rapid sea level rise, with a thickness of 0.5โ2.8ย m that gradually thickens basinward. The TOC content, averaging 5.4%, gradually decreases basinward, with four distinct stacking patterns. The mineral composition and thickness of the Longmaxi shale are related closely to rapid transgression, biology, and volcanism during the period of sedimentation. Rapid transgression has led to a decrease in terrestrial input and shale thickness. In addition, biological activity and volcanism have caused the prevalence of microcrystalline quartz. Shales with high TOC content are related to anoxic conditions, along with low sedimentation rates and high primary productivity. The combination of an anoxic water column, weak dilution, and enhanced organic matter (OM) supply have enhanced the preservation of the OM. The four TOC stacking patterns are related to the water depth. The supply of clay minerals decreases with increasing water depth, whereas the degradation and recycling of OM decrease the TOC content. The sediment accommodation increases with increasing water depth, resulting in four TOC stacking patterns.
- Europe (1.00)
- Asia > China > Sichuan Province (0.69)
- Phanerozoic > Paleozoic > Silurian > Llandovery (1.00)
- Phanerozoic > Mesozoic (1.00)
- Phanerozoic > Paleozoic > Ordovician (0.98)
- Geology > Rock Type > Sedimentary Rock > Clastic Rock > Mudrock > Shale (1.00)
- Geology > Mineral (1.00)
- 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...)
- Reservoir Description and Dynamics > Unconventional and Complex Reservoirs > Shale gas (1.00)
- Reservoir Description and Dynamics > Reservoir Characterization > Seismic processing and interpretation (1.00)
- Reservoir Description and Dynamics > Reservoir Characterization > Exploration, development, structural geology (1.00)
- Health, Safety, Environment & Sustainability > Environment (1.00)
The Lower Silurian Longmaxi rapid-transgressive black shale and organic matter distribution on the Upper Yangtze Platform, China
Shi, Zhensheng (PetroChina Research Institute of Petroleum Exploration and Development) | Zhou, Tianqi (PetroChina Research Institute of Petroleum Exploration and Development) | Qi, Ling (PetroChina Research Institute of Petroleum Exploration and Development)
Abstract The characteristics and formation of maximum flooding (MF) black shales are important aspects in defining the geology of fine-grained reservoirs. The MF black shales are located at the bottom of the Longmaxi Formation on the Upper Yangtze Platform, corresponding to graptolite zone LM1. Seismic interpretation, X-ray diffraction entire rock analysis, total organic carbon (TOC) tests, and field emission scanning electron microscopy analysis indicate that the MF black shales have an average content of 49.3% quartz (85% clay size), 10.5% calcite, 8.4% dolomite, and 23.4% clay minerals. The quartz content increases basinward, whereas the clay mineral content decreases. The shale has developed during rapid sea level rise, with a thickness of 0.5โ2.8ย m that gradually thickens basinward. The TOC content, averaging 5.4%, gradually decreases basinward, with four distinct stacking patterns. The mineral composition and thickness of the Longmaxi shale are related closely to rapid transgression, biology, and volcanism during the period of sedimentation. Rapid transgression has led to a decrease in terrestrial input and shale thickness. In addition, biological activity and volcanism have caused the prevalence of microcrystalline quartz. Shales with high TOC content are related to anoxic conditions, along with low sedimentation rates and high primary productivity. The combination of an anoxic water column, weak dilution, and enhanced organic matter (OM) supply have enhanced the preservation of the OM. The four TOC stacking patterns are related to the water depth. The supply of clay minerals decreases with increasing water depth, whereas the degradation and recycling of OM decrease the TOC content. The sediment accommodation increases with increasing water depth, resulting in four TOC stacking patterns.
- Europe (1.00)
- Asia > China > Sichuan Province (0.69)
- Phanerozoic > Paleozoic > Silurian > Llandovery (1.00)
- Phanerozoic > Mesozoic (1.00)
- Phanerozoic > Paleozoic > Ordovician (0.98)
- Geology > Rock Type > Sedimentary Rock > Clastic Rock > Mudrock > Shale (1.00)
- Geology > Mineral (1.00)
- 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...)
- Reservoir Description and Dynamics > Unconventional and Complex Reservoirs > Shale gas (1.00)
- Reservoir Description and Dynamics > Reservoir Characterization > Seismic processing and interpretation (1.00)
- Reservoir Description and Dynamics > Reservoir Characterization > Exploration, development, structural geology (1.00)
- Health, Safety, Environment & Sustainability > Environment (1.00)
Integrating Embedment and Creep Behavior for Multisize Proppant in Shale: Conceptual Model and Validation
Cheng, Qiaoyun (Key Laboratory of Tectonics and Petroleum Resources of the Ministry of Education, School of Earth Resources, and Hubei Key Laboratory of Marine Geological Resources, China University of Geosciences) | Zhou, Sandong (Key Laboratory of Tectonics and Petroleum Resources of the Ministry of Education, School of Earth Resources, and Hubei Key Laboratory of Marine Geological Resources, China University of Geosciences (Corresponding author)) | Li, Bobo (College of Mining, Guizhou University) | Pan, Zhejun (Key Laboratory of Continental Shale Hydrocarbon Accumulation and Efficient Development, Ministry of Education, Northeast Petroleum University) | Liu, Dameng (Coal Reservoir Laboratory of National Engineering Research Center of CBM Development & Utilization, School of Energy Resources, China University of Geosciences) | Yan, Detian (Key Laboratory of Tectonics and Petroleum Resources of the Ministry of Education, School of Earth Resources, China University of Geosciences)
Summary The embedment of multisize proppant in fractures and the creep behavior of the shale will affect fracture permeability, yet the combination of the two factors has not been well studied and understood. In this work, the impact of graded arrangement of multisize proppant on fracture permeability is studied considering proppant embedment and shale creep in a hydraulic fracture. The Hertz contact theory is used to quantify the depth of embedment for proppant with different particle sizes, and the Burgers model is used to describe the creep behavior of shale. Then, a permeability model considering the effects of multisize proppant embedment with shale creep is developed and verified. The results show that, under the combined effect of shale creep and proppant embedment, the reduction in permeability of the proppant arrangement with equal amount of three particle sizes is about twice that of two particle sizes. It also shows that there is an optimal Youngโs modulus ratio that allows for minimal proppant embedment when the Youngโs moduli of proppant and shale are in the same order of magnitude. Moreover, creep is positively correlated with loading pressure, loading time, and clay mineral content in the shale and there is a clear correspondence between shale creep, fracture width, and permeability variation. It is suggested that proppant type, size, mixing ratio, and fracturing parameters for shale reservoirs should be optimized by combining reservoir mineralogy and rock mechanics to reduce the cumulative effect of shale creep on long-term productivity. This work is useful for optimizing the hydraulic fracturing design for shale reservoirs and improving the efficiency of hydraulic fracturing to increase permeability.
- Asia > China (1.00)
- North America > United States > Texas (0.93)
- Research Report > New Finding (0.66)
- Research Report > Experimental Study (0.66)
- South America > Argentina > Patagonia > Neuquรฉn > Neuquen Basin > Vaca Muerta Shale Formation (0.99)
- 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)
- (6 more...)
Stress Evolution and Permeability Enhancement Mechanism of Multistage Cavity Completion in Coalbed Methane Horizontal Wells
Yang, Ruiyue (National Key Laboratory of Petroleum Resources and Engineering, China University of Petroleum, Beijing (Corresponding author)) | Chen, Jianxiang (National Key Laboratory of Petroleum Resources and Engineering, China University of Petroleum, Beijing) | Qin, Xiaozhou (National Key Laboratory of Petroleum Resources and Engineering, China University of Petroleum, Beijing) | Huang, Zhongwei (National Key Laboratory of Petroleum Resources and Engineering, China University of Petroleum, Beijing) | Li, Gensheng (National Key Laboratory of Petroleum Resources and Engineering, China University of Petroleum, Beijing) | Liu, Liangliang (State Key Laboratory of Coal and Coalbed Methane Co-mining)
Summary Coalbed methane (CBM) is an important clean energy resource. However, low gas production rate, especially in areas where hydraulic fracturing is notoriously inefficient, is the major obstacle that restricts the commercial development of CBM. Multistage horizontal well cavity completion has been observed to be successful in improving gas production rates in the Zhengzhuang block, Qinshui Basin, China. It has resulted in rates that are 1.5 times higher than the average production level achieved through horizontal well hydraulic fracturing. However, the stimulation mechanisms and major factors determining completion efficiency are still poorly understood. In this paper, we established a numerical model using the finite discrete element method (FDEM) to compute the stress evolution and fracture-network patterns. The accuracy of the model has been confirmed by analytical and numerical solutions. Subsequently, a series of parametric studies were performed to quantitatively analyze the mechanisms of multistage cavities influencing the stress evolution and fracture geometries in CBM reservoirs. Finally, we investigated a field case in an actual horizontal well located at the Qinshui Basin, where 17 cavity stages were completed. This case study further shed light upon the well completion strategies and optimization decisions. Implications and suggestions were also provided for field treatments to enhance the completion efficiency. The results demonstrate that FDEM can provide new insights into cavity completion mechanisms by explicitly accounting for fracture and fragmentation process at the field scale. The complex-fracture networks originated from multistage cavities consist of cavity-induced shear fractures, tensile fractures, mixed-mode fractures, and activated multiscale natural fractures, which is the primary reason for enhanced permeability and the essential difference from hydraulic fracturing. Compared with a single cavity, the interactions among multiple cavities can further promote the fracture-network connectivity and thus enlarge the stress-relief area and fracture area substantially. The selections of cavity geometrical parameters, including spacing, length, diameter, and number, have significant impacts on stress evolution (both magnitude and stress-relief area) and fracture patterns (such as fracture-network geometry, interconnectivity, propagation direction, and area). Stress evolution and fracture patterns reproduced from a field case in the Qinshui Basin can provide critical learnings for the industry in designing horizontal well cavity completion schemes. The key findings of this study are expected to deliver fundamental and practical guidelines for the horizontal well cavity completion in CBM or other unconventional oil and gas exploitation.
- North America > Canada (1.00)
- Asia > China (1.00)
- North America > United States > Colorado (0.28)
- (2 more...)
- Geology > Geological Subdiscipline > Geomechanics (1.00)
- Geology > Rock Type > Sedimentary Rock > Organic-Rich Rock > Coal (0.93)
- Geophysics > Borehole Geophysics (0.46)
- Geophysics > Seismic Surveying (0.46)
- North America > United States > New Mexico > San Juan Basin > Fruitland Formation (0.99)
- North America > United States > Colorado > San Juan Basin (0.99)
- North America > United States > Arizona > San Juan Basin (0.99)
- (7 more...)
Surfactant Enhanced Oil Recovery Improves Oil Recovery in a Depleted Eagle Ford Unconventional Well: A Case Study
Ataceri, I. Z. (Texas A&M University) | Saputra, I. W. R. (Texas A&M University) | Bagareddy, A. R. (Texas A&M University) | Elkady, M. H. (Texas A&M University) | Schechter, D. S. (Texas A&M University) | Haddix, G. W. (Third Wave Production LLC (Corresponding author)) | Brock, V. A. (Third Wave Production LLC) | Raney, K. H. (Third Wave Production LLC) | Strickland, C. W. (Third Wave Production LLC) | Morris, G. R. (Auterra Operating LLC)
Summary A simple huff โnโ puff (HnP) injection and flowback using a nonionic surfactant solution to drive enhanced oil recovery (EOR) in a depleted Eagle Ford โblack oilโ unconventional well has been executed and analyzed. The pilot injection was performed in December 2020, with pressures below the estimated fracture gradient. More than 12,300 bbl of surfactant solution were injected into the 6,000-ft lateral. In January 2021, the well was put back on production with oil and water flow rate data being gathered and samples collected. Within 3 months of the well being put back onto production after surfactant stimulation, the well produced at oil rates over five times what it had produced before stimulation. The current oil rates (through October 2022; 22 months after stimulation) are still twice the prestimulation rates. Using a long-term hyperbolic fit to historical data as the โmost likelyโ production scenario in the absence of stimulation as a โbaseline,โ incremental recovery was estimated using the actual oil production data to date. Economic analysis with prevailing West Texas Intermediate (i.e., WTI) prices at the time of production and the known costs of the pilot result in project payout time less than 1 year and project internal rate of return in excess of 80%, with only incremental production to date. These results prove the potential for technoeconomic viability of HnP EOR techniques using surfactants for wettability alteration in depleted unconventional oil wells. The well was chosen from a portfolio of unconventional Eagle Ford black oil window wells that were completed in the 2012โ2014 time frame. The goal of the test was to demonstrate successful application of laboratory work to the field and economic viability of surfactant-driven water imbibition as a means of incremental EOR. The field design was based on laboratory work completed on oil and brine samples from the well of interest, with rock sampled from a nearby well at the same depth. The technical and economic objectives of the field test were to (1) inject surfactant solution to contact sufficient matrix surface area that measurable and economically attractive amounts of oil could be mobilized, (2) measure the amount of surfactant produced in the flowback stream to determine the amount of surfactant retained in the reservoir, and (3) prove the concept of using wettability alteration in conjunction with residual well energy in a depleted well to achieve economically attractive incremental recovery. Surfactant selection was completed in the laboratory using oil and brine gathered from potential target wells, and rock from nearby wells completed in the same strata. Several surfactant formulations were tested, and a final nonionic formulation was chosen on the basis of favorable wettability alteration and improved spontaneous imbibition recovery. The design for the pilot relied on rules of thumb derived from unconventional completion parameters. Rates, pressures, and injectant composition were carefully controlled for the single-day โbullheadโ injection. Soak time between injection and post-stimulation restart of production was inferred from laboratory-scale imbibition trials. Post-stimulation samples were gathered, while daily oil and water rates were monitored since production restart. Flowback samples were analyzed for total dissolved solids (TDS), ions, and surfactant concentration.
- Geology > Mineral (1.00)
- Geology > Petroleum Play Type > Unconventional Play > Shale Play (0.46)
- Geology > Geological Subdiscipline > Geomechanics (0.46)
- Energy > Oil & Gas > Upstream (1.00)
- Materials > Chemicals > Commodity Chemicals > Petrochemicals (0.68)
- Reservoir Description and Dynamics > Unconventional and Complex Reservoirs > Shale gas (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)
- (5 more...)
Investigating the Impact of Aqueous Phase on CO2 Huff โnโ Puff in Tight Oil Reservoirs Using Nuclear Magnetic Resonance Technology: Stimulation Measures and Mechanisms
Liu, Junrong (School of Petroleum Engineering, China University of Petroleum (East China)) | Li, Hangyu (Key Laboratory of Unconventional Oil & Gas Development, China University of Petroleum (East China)) | Liu, Shuyang (SchoolSchool of Petroleum Engineering, China University of Petroleum (East China)) | Xu, Jianchun (Key Laboratory of Unconventional Oil & Gas Development, China University of Petroleum (East China) (Corresponding author) of Petroleum Engineering, China University of Petroleum (East China)) | Wang, Xiaopu (School of Petroleum Engineering, China University of Petroleum (East China)) | Tan, Qizhi (Key Laboratory of Unconventional Oil & Gas Development, China University of Petroleum (East China))
Summary CO2 huff โnโ puff is a promising enhanced oil recovery (EOR) technique for tight/shale reservoirs, also enabling CO2 geological storage. However, the effectiveness of this method can be significantly affected by the aqueous phase resulting from connate water and hydraulic fracturing. The mechanism underlying the influence of the aqueous phase on oil recovery during CO2 huff โnโ puff, as well as the corresponding stimulation methods in such scenarios, remain unclear and warrant further study. To investigate this, we utilized a nuclear magnetic resonance (NMR) instrument to track the movement of fluids during CO2 huff โnโ puff under water invasion conditions. The impact of the invaded aqueous phase on oil recovery was examined, and the impact of different treatment parameters was explored. The results show that the aqueous barrier formed by water invasion alters the pathway of CO2 diffusion to matrix oil. This alteration leads to a diminished concentration of CO2 in the oil phase, which, in turn, results in a substantial reduction in oil recovery. Consequently, the performance of CO2 huff โnโ puff is highly sensitive to the water phase. Nevertheless, the oil recovery dynamics in cyclic CO2 huff โnโ puff under water invasion exhibit distinctive patterns compared with those without water invasion. These differences manifest as notable low oil recovery in the first cycle, followed by a rapid increase in the second cycle. This behavior primarily arises from the expulsion of a significant portion of the invaded water from the macropores after the first cycle. However, the effectiveness of this mechanism is limited in micropores due to the challenging displacement of trapped water in such pores. Raising the injection pressure mainly boosts oil recovery in macropores, with minimal response in micropores. Yet, the achievement of miscibility does not lead to a substantial improvement in the CO2 huff โnโ puff performance, primarily due to the constraints imposed by the limited CO2 dissolution through molecular diffusion Additionally, we have proposed three stimulation mechanisms achieved by lengthening the soaking time under water invasion conditions. First, the prolonged soaking time increases the concentration of CO2 molecules that diffuse into the matrix oil. Second, it promotes the imbibition of the trapped water on the fracture surface into the deeper matrix to alleviate water blockage. Finally, the invaded water in macropores displaces oil in micropores by capillary force during the soaking period.
- North America > United States > Texas (0.46)
- North America > Canada > Alberta (0.46)
- Research Report > New Finding (1.00)
- Research Report > Experimental Study (0.88)
- Geology > Mineral (1.00)
- Geology > Rock Type > Sedimentary Rock > Clastic Rock > Mudrock > Shale (0.49)
- 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)
- (6 more...)
Summary The heterogeneity of tight reservoirs, along with their complex geologic characteristics and the diverse completion practices used, presents challenges in developing accurate models to forecast the productivity for multifractured horizontal wells (MFHWs) completed in these reservoirs. This paper introduces a new early-time diagnostic tool that leverages early-time two-phase flowback data to forecast long-term productivity and evaluate completion efficiency. To achieve this, two novel models were developed. The first model, the water/oil-ratio model (WORM), uses a hybrid analytical and data-driven approach to describe the observed log-linear relationship between water/oil ratio (WOR) and load recovery (amount of fracturing water produced back after hydraulic fracturing operations) as an analogy to the log-linear relationship between the water/oil relative permeability ratio and water saturation. Next, a neural network is used to couple WORM parameters with key petrophysical properties to analyze the impact of fracture and formation properties on WOR performance, predict WOR as a function of load recovery, forecast ultimate load recovery, and estimate effective fracture volume and initial water saturation in fracture. The second model, the cumulative oil production model (COPM), is a data-driven model that predicts oil production as a function of load recovery during the matrix-dominated flow regime. The application of WORM and COPM on Niobrara and Codell formation wells showed that Codell wells generally exhibit better load recovery and larger effective fracture volume compared with Niobrara wells, but both formations exhibit similar oil recovery performance, indicating independent flow regimes within the effective fractures. The effective fracture volume estimated by WORM was validated against the estimated volume from recorded microseismic events. The results also showed that using the same completion practice to achieve a similar effective fracture volume in child wells does not necessarily lead to similar oil productivity. This paper introduces a holistic workflow that links early two-phase flowback data with well productivity and completion efficiency and is anticipated to aid petroleum engineers in optimizing hydraulic fracturing operations.
- North America > United States > Texas (0.93)
- North America > United States > Colorado (0.66)
- Research Report > New Finding (0.93)
- Research Report > Experimental Study (0.67)
- Geology > Geological Subdiscipline > Geomechanics (1.00)
- Geology > Geological Subdiscipline > Economic Geology > Petroleum Geology (0.41)
- North America > United States > Wyoming > DJ (Denver-Julesburg) Basin > Codell Formation (0.99)
- North America > United States > Texas > Anadarko Basin (0.99)
- North America > United States > Kansas > Anadarko Basin (0.99)
- (10 more...)