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Results
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...)
Using Natural Gas Liquid for EOR in a Huff-N-Puff Process – A Feasibility Study
Alinejad, Amin (Civil and Environmental Engineering, School of Mining and Petroleum Engineering, University of Alberta, Edmonton, Alberta, Canada) | Dehghanpour, Hassan (Civil and Environmental Engineering, School of Mining and Petroleum Engineering, University of Alberta, Edmonton, Alberta, Canada)
Abstract This is a feasibility study investigating the application of natural gas liquid (NGL) in a Huff-n-Puff process for enhanced oil recovery from unconventional tight-oil reservoirs. We use a state-of-the-art high-pressure and high-temperature visualization cell to capture real-time NGL-oil interactions throughout the experiment, both in bulk-phase conditions and in the presence of a core sample. We utilize an ultratight Eagle Ford shale sample extracted from horizontal section of a wellbore. The experiments are conducted at a reservoir pressure and temperature of 3,200 psig and 133℃, respectively with NGL being injected at a liquid state. Our findings indicate the notable solubility of NGL in oil, primarily due to NGL's intermediate hydrocarbon components. During the soaking stage, these intermediate hydrocarbon components of oil partition into the NGL, resulting in enhanced solubility of NGL in oil and a subsequent decrease in oil volume. This observation is confirmed by the gradual color change of NGL to amber. We hypothesize that the NGL is spontaneously and forcefully imbibed into the oil-saturated core plug, displacing the oil, resembling a counter-current surfactant imbibition process. However, due to strong solubility of NGL in oil and the active hydrocarbon component's extraction mechanism, the produced oil is dissolved in NGL rather than forming oil droplets on the rock surface. Following the depletion stage, we observe two sequential oil production stages: 1) a prolonged single-phase flow stage until reaching the saturation pressure of the NGL, with total system compressibility as the dominant oil-recovery mechanism and 2) a two-phase flow region with solution-gas drive as the key oil-recovery mechanism. Remarkably, after one cycle of NGL HnP, most of the oil is recovered which surpasses the recovery factors observed in natural gas or CO2 HnP studies.
- North America > United States > Texas (0.89)
- North America > Canada (0.69)
- Geology > Rock Type > Sedimentary Rock > Clastic Rock > Mudrock > Shale (0.37)
- Geology > Geological Subdiscipline (0.35)
- Geology > Petroleum Play Type > Unconventional Play > Shale Play (0.35)
- 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)
- North America > Canada > Alberta > Progress Field > Aec Progress 11-33-78-10 Well (0.93)
Optimal Treatment and Reuse of Flowback and Produced Water: Selective Removal of Problematic Cations for Stability of Friction Reducers
Zhang, Yanze (University of Alberta) | Ali, Wajid (University of Alberta) | Jiang, Chunqing (Natural Resources Canada Geological Survey of Canada, Calgary) | Dehghanpour, Hassan (University of Alberta)
Abstract The oil and gas industry has been considering treatment and reuse of produced water for hydraulic fracturing of unconventional reservoirs to reduce environmental footprints and economic costs. In this paper, we studied the compatibility of Duvernay flowback and produced water (FPW) with anionic polyacrylamide-based friction reducer (FR) sample. Shear viscosity, particle size distribution, and viscoelasticity measurements were conducted to assess the performance of FR in both untreated and treated PW using Na2CO. The experimental results indicate that Ca and Mg are removed by up to 92.89% and almost 100%, respectively, at pH value of 11.5±0.10 and temperature of 80°C. The measured viscosity profile of FR in treated and untreated FPW are similar, suggesting that removing Ca, Mg, and Fe from FPW does not significantly increase the viscosity of slickwater. The viscoelastic properties of slickwater are found to be significantly increased when Ca concentration is decreased to 933.10 mg/L, and the size distribution of FR molecules become more uniform when the Ca and Mg concentrations are reduced to 1670.7 mg/L and <0.01 mg/L, respectively. Overall, a minimum Ca concentration of 1670.7 mg/L and Mg concentration of <0.01 mg/L are needed to prepare stable slickwater with Duvernay FPW. Introduction The extraction of oil from low-permeability reservoirs, such as shale and tight sandstones, poses significant challenges due to the restricted flow of oil and gas through the formation. Hydraulic fracturing, commonly known as "fracking" is a widely accepted technique in the petroleum industry that is used to improve the permeability and productivity of such reservoirs (Guo et al., 2022). The hydraulic fracturing process entails injecting a mixture of fluids at high pressure into the wellbore, including water, proppants, and various additives such as friction reducers, surfactant, and biocides. The proppants help maintain the fractures’ aperture, while the friction reducers and surfactant additives mitigate friction and biocide prevents bacterial growth that may clog the fractures (Barati & Liang, 2014).
- North America > United States (1.00)
- North America > Canada > Alberta (0.68)
- Geology > Rock Type > Sedimentary Rock > Clastic Rock (0.54)
- Geology > Geological Subdiscipline > Geomechanics (0.34)
- 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 > Pennsylvania > Appalachian Basin > Marcellus Shale Formation (0.99)
- (3 more...)
Abstract Generally, pressure and fluid communications between parent and child wells which is referred to as frac hit deteriorate the production performance of the parent well. Small pre-loading technique is one of the cost-efficient and operationally simple strategies to mitigate frac hit. However, the production outcome of the parent well is unsatisfactory after flowback of pre-loading fluid in most of the pilots. To overcome this negative impact, we intend to evaluate the extent of additional oil recovery by imbibition of fluids with two types of non-ionic surfactant additives (SF-1 and SF-2) during pre-loading and flowback processes. We utilize a high-pressure and high-temperature visualization cell to conduct the pre-loading experiments using Montney rock and fluid samples. We restore the initial reservoir condition in the core plug and then simulate the primary production stage of the reservoir to establish a depleted core plug. Then, we conduct two sets of experiments on the depleted core plug: 1) soaking the plug with SF-1 surfactant solution under atmospheric conditions and 2) pre-loading the depleted core plug with the SF-1 surfactant solution at a pressure of 3,500 psig and reservoir temperature of 78°C. We also pre-load an oil-saturated core plug with SF-2 surfactant solution at similar operational conditions. Our results show that 31.4% of the original oil-in-place is produced during the primary production stage with solution-gas drive as the dominant oil-recovery mechanism. We observe an additional 3.9% (of original oil-in-place) oil recovery due to counter-current imbibition of the SF-1 surfactant solution after soaking under atmospheric conditions. The interfacial tension reduction and wettability alteration are two possible oil-recovery mechanisms during surfactant soaking. Pre-loading the depleted core plug with SF-1 surfactant solution at a set pressure of 3,370 psig and a temperature of 78°C does not result in additional oil recovery. However, pre-loading the oil-saturated core plug with SF-2 surfactant solution at the same operational conditions results in an approximately 29.6% oil recovery. We observe oil droplets formed on the rock surface during soaking of the oil-saturated plug with SF-2 surfactant solution. We conclude that longer soaking periods may assist in additional oil recovery in core plugs with depleted state compared to the non-depleted plugs.
- North America > United States > Texas (0.68)
- North America > Canada > Alberta (0.46)
- Research Report > New Finding (1.00)
- Research Report > Experimental Study (0.86)
- Geology > Petroleum Play Type > Unconventional Play > Shale Play (0.93)
- Geology > Rock Type > Sedimentary Rock (0.69)
- Geology > Mineral > Silicate (0.68)
Abstract Gas Huff-n-Puff (HnP) has been implemented as an enhanced oil recovery technique to recover the residual oil after primary production from unconventional wells. Natural gas, nitrogen, and carbon dioxide can be used as candidates for injecting fluids in HnP operations. However, natural gas is the common choice for injecting gas due to its availability and incentives for reducing the venting and flaring of the produced gas. So far, some experimental studies attempted to investigate the natural gas HnP on Eagle Ford shale. However, the associated oil-recovery mechanisms are poorly understood. In this study, we perform natural gas HnP experiments using C1 and C1-C2 on Eagle Ford shale samples under representative reservoir conditions. We use a custom-designed visualization cell to observe the interactions of gas, oil, and shale during the whole HnP cycle. Consistent with field operations, we adopt a hybrid depletion strategy of steep depletion at the initial stages followed by a slow depletion at later stages. We select the pressure depletion rates by downscaling field data of a HnP operation in the Eagle Ford Formation. Our results reveal that solution-gas drive or gas expansion during the depletion stage is the dominant oil-recovery mechanism. However, the extended soaking period helps in oil recovery by allowing sufficient gas diffusion into the core plug. We observe that enrichment of injecting gas by C2 results in earlier and more oil production compared to pure C1. The ultimate oil recovery factor after a single-cycle C1 and C1-C2 HnP is 46.1 and 55.6% of the original oil-in-place, respectively. We estimate the apparent diffusivity coefficient of C1 and C1-C2 in oil-saturated shale plugs using available analytical models. The estimated apparent diffusivity coefficients are in the order of 10 m/s with an 8% higher diffusivity coefficient in the case of C1-C2 compared to the case of C1.
- 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)
- North America > Canada > Alberta > Progress Field > Aec Progress 11-33-78-10 Well (0.93)
- Reservoir Description and Dynamics > Unconventional and Complex Reservoirs > Shale oil (1.00)
- Reservoir Description and Dynamics > Unconventional and Complex Reservoirs > Shale gas (1.00)
- Reservoir Description and Dynamics > Improved and Enhanced Recovery > Thermal methods (1.00)
- Reservoir Description and Dynamics > Improved and Enhanced Recovery > Gas-injection methods (1.00)
Abstract Infill drilling is becoming a common practice for more efficient development of tight reservoirs. However, child-well stimulation may lead to a parent-child well interference or a fracture hit. To mitigate the negative impacts of a fracture hit, the parent well is preloaded before the stimulation of child wells. Then, the injected water during the pre-loading period is later produced back to the surface. The preloading flowback (second flowback) data of parent wells may provide an opportunity for fracture charactrization. The main objective of this research is to compare the responses of initial and second flowback to capture the changes in fracture characterstics after production and preload processes. We construct rate-normalized pressure (RNP) diagnostic plots on both initial and second flowback (IFB and SFB, respectively) of six multi-fractured horizontal wells completed in Niobrara and Codell formations in DJ Basin. In general, the slope of RNP versus MBT during the SFB period is higher than that during the IFB period, except for well 1. We estimate the changes in average effective fracture volume (Vef) by analyzing the changes in the RNP slope and total compressibility during these two flowback periods. Compared to the IFB period, the Vef is generally decreased during the SFB period. The loss percentage of effective fracture volume (RVef) is estimated at 10-40%. We also compare the drive mechanisms for the two flowback periods by calculating the compaction drive index (CDI), hydrocarbon-drive index (HDI), and water-drive index (WDI). The dominant driving mechanism during both flowback periods is CDI, but its contribution is reduced by 12% in the SFB period. This drop is generally compensated by a relatively higher HDI during this period. Finally, we investigate the effects of duration of production (tp) on RVef. There is a positive correlation between tp and RVef during the two flowback periods. Therefore, the loss of effective fracture volume might be attributed to the pressure depletion in fractures caused by the long production period (more than 800 days).
- North America > United States > Colorado (0.69)
- North America > United States > Texas (0.68)
- North America > United States > Wyoming > Laramie Basin > Niobrara 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)
- (37 more...)
Port-Opening Falloff Test: A Complementary Test to Diagnostic Fracture Injection Test
Hossain, Sabbir (University of Alberta) | Dehghanpour, Hassan (University of Alberta (Corresponding author)) | Ezulike, Obinna (University of Alberta) | Dotson, Bryan (BP America) | Motealleh, Siyavash (BP America)
Summary Conventional fracture injection/falloff tests, such as minifrac or diagnostic fracture injection test (DFIT), are commonly used to characterize shale and tight reservoirs. For ultralow-permeability reservoirs, a reliable DFIT requires a long falloff period after a short injection period. A long falloff observation period of weeks or months is often not economically viable. In addition, the recent economic downturn requires operators to seek cost-effective alternatives to further optimize expenditures. An alternative to a DFIT is a port-opening falloff test (POFOT). Many horizontal completions use a pressure-activated sleeve in the toe of the well to provide formation access after the casing integrity test. Most sleeves open at a pressure in excess of the formation breakdown pressure, after which the wellbore pressure declines toward reservoir pressure. This study first introduces the concept of the POFOT as a novel physical test. A new test method must demonstrate that it accesses the formation of interest and that the data obtained are applicable. A workflow is developed to demonstrate this and is applied to falloff data from POFOTs conducted in five horizontal wells completed in five formations. The results show that the fluid leaving the port is highly likely to break down both the cement sheath and the matrix and create a fracture which then closes. Observation of the well pressure after port opening resembles that from a DFIT. However, without a fixed-duration and constant-rate injection period, there is no accepted method to apply. Nevertheless, both qualitative and quantitative analyses of the falloff data provide a good estimation of reservoir pressure with a reasonable approximation of fracture closure when compared with the estimates from DFIT analysis from offset wells. The key challenges in parameter estimation, besides the development of an appropriate analysis method, are short falloff data and noisy early-time data due to wellbore resonance (WBR), low-resolution gauges, and change in sampling frequency.
- North America > United States > Texas (1.00)
- North America > Canada > Alberta (0.68)
- Asia > Middle East (0.67)
- Research Report > New Finding (1.00)
- Research Report > Experimental Study (1.00)
- Geology > Geological Subdiscipline > Geomechanics (1.00)
- Geology > Rock Type > Sedimentary Rock > Clastic Rock > Mudrock > Shale (0.35)
- 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)
- (4 more...)
- Well Completion > Hydraulic Fracturing (1.00)
- Reservoir Description and Dynamics > Reservoir Characterization > Reservoir geomechanics (1.00)
- Reservoir Description and Dynamics > Formation Evaluation & Management > Pressure transient analysis (1.00)
- Reservoir Description and Dynamics > Formation Evaluation & Management > Drillstem/well testing (1.00)
Abstract We analyze flowback production data of 502 multi-fractured horizontal oil and gas wells completed in the Montney Formation and 83 oil wells completed in the Duvernay and Horn River Formations. The main goal of this paper is to evaluate the possibility of distinguishing between formation and fracturing water based on the water-flowback response. We hypothesize that: 1) the slope of water-flowback harmonic decline (HD) profile is reversely proportional to formation water mobility, 2) the deviations from the unit slope on rate-normalized pressure (RNP) plots is proportional to the slope of HD, and 3) the slope of water-flowback HD correlates with the initial water saturation (Swi). To verify our hypothesis, we 1) classify the observed HD trends of water-flowback rate based on slopes, 2) construct RNP diagnostic plots of the studied wells, 3) analyze log data and estimate average Swi by using Archie equation (1952) for the studied wells. 4) investigate the effects of Swi on the water-flowback pattern. The results show that there are two distinct flowback patterns. The first flowback pattern shows sharp slope (>101/day) of water-flowback HD profile and relatively high slope values (0.64 to 0.984 kpa/m3) of the corresponding RNP plots. However, the second pattern shows very low slope of HD (<5 × 10 1/day), with some wells showing no significant decline of water rate through the entire flowback process, also relatively low slope values (0 to 0.23) of the corresponding RNP plots. Analysis of the log data shows a positive correlation between Swi and slope of water-flowback HD profile. We also found that the slopes are proportional to the slope of RNP. These results indicate that as Swi increases, slope of HD decreases and there is more deviation from the unit-slope on the RNP plots.
- Research Report > New Finding (0.49)
- Research Report > Experimental Study (0.34)
Abstract The non-thermal solvent-based processes for bitumen extraction consume less energy and water, and thus, have less impacts on the environment compared with the steam-based thermal processes. The objective of this paper is to investigate the mechanisms responsible for propane transport into and bitumen production from oil-sand core samples during the cyclic solvent injection (CSI). We use a state-of-the-art high-pressure and high-temperature (HPHT) visualization cell to investigate non-equilibrium propane-bitumen interactions during CSI. We inject propane into the cell containing a bitumen-saturated core plug representing in-situ reservoir conditions. Three sets of tests with different propane vapor (C3(v)) to liquid (C3(l)) ratio are conducted (set 1 with C3(l), set 2 with C3(l)-C3(v) mixture, and set 3 with C3(v)). After the CSI tests, the final bitumen recovery factor is calculated by the weight-balance method and the precipitated asphaltene content caused by propane-bitumen interactions is also measured using a distillation apparatus. When the core is fully immersed in C3(l), the cell pressure rapidly declines during the early soaking process, and then, it declines gradually. However, no obvious pressure decline can be observed when C3(v) is present in the system. This can be explained by the higher compressibility of C3(v) compared to C3(l), leading to a less significant pressure decline during the soaking period. A light hydrocarbon phase is produced from the core at the end of the depletion process, indicating the extraction of light components of oil by propane even at low-temperature conditions. The bitumen recovery factor is the lowest (11.93%) in set 1 when the core is soaked in C3(l), while that is the highest (14.73%) in set 3 when the core is soaked in C3(v). Also, the bitumen production stops quickly at the early soaking period in set 1. This is because asphaltene precipitation is more significant when the C3(l) is present in the system. The propane density in liquid state is higher than that in vapor state, leading to more bitumen-propane interactions and more asphaltene precipitation. The precipitated asphaltene blocks the pore network and inhibits bitumen production. Our results show that increasing C3(v) to C3(v) ratio decreases the amount of asphaltene precipitation, and in turn, increases bitumen recovery factor.
- Materials > Chemicals > Commodity Chemicals > Petrochemicals (1.00)
- Energy > Oil & Gas > Upstream (1.00)
- North America > Canada > Alberta > Western Canada Sedimentary Basin > Alberta Basin > Clearwater Formation (0.99)
- North America > Canada > Alberta > Athabasca Oil Sands > Western Canada Sedimentary Basin > Alberta Basin > Hangingstone Oil Sands Project (0.99)
- North America > Canada > Alberta > Western Canada Sedimentary Basin > Alberta Basin > Cold Lake Oil Sands Project > Clearwater Formation (0.98)
Linking Flowback Recovery to Completion Efficiency: Niobrara-DJ Basin Case Study
Moussa, Tamer (University of Alberta) | Barhaug, Jessica (Great Western Operating Company LLC.) | Witt, Darby (Cordax Evaluation Technologies INC.) | Hawkes, Robert (Cordax Evaluation Technologies INC.) | Dehghanpour, Hassan (University of Alberta)
Abstract Near wellbore complexity is a current topic of discussion among geoscience and engineering disciplines across North America. Asset teams are constantly investing money and resources into the variety of near- and far-field wellbore diagnostic techniques to ascertain completion efficiency. These range from high-cost microseismic for far-field fracture placement to higher risk technologies such as fiber optics, cameras, and production logging tools. These techniques are generally used for parameter constraints for rate-transient-analysis (RTA) that requires months (and sometimes years) of production after post-frac flowback. Therefore, in this study we utilize flowback water-oil-ratio (WOR) as a diagnostic tool to provide early-time feedback for completion-efficiency evaluation. We analyze flowback, post-flowback and completion-design data of 19 multi-fractured horizontal wells (MFHWs) completed in Niobrara and Codell formations that are classified into parent and child groups. Child wells are then sub-clustered into Zipper-1 and -2 completed with more and less intense completion strategy, respectively. First, we analyze the flowback rate and pressure profiles of the 19 wells to estimate initial pressure in the stimulated area around wellbore and validate it against the outcomes of diagnostic fracture injection test (DFIT). Second, we apply rate-normalized-pressure (RNP) diagnostic analysis to a) investigate flow regimes during flowback and post-flowback periods; and b) assess interference between parent and child wells. Third, we use WOR diagnostic plots to estimate ultimate load recovery (ULR) and calculate initial effective fracture volume as two indicators for completion efficiency. We also cross-check the estimated effective fracture volume with microseismic dimensions. Finally, we apply rate-decline analysis on oil production data to predict ultimate oil recovery (UQo), assuming a critical oil rate of 1 stbd, and use it as a third performance indicator to evaluate the completion-design efficiency of each group. Child wells show 32% more load recovery compared with the parent wells. However, the parent wells show 38% and 50% more 9-months cumulative oil production (Qo) and UQo, respectively. For both the parent and child wells, more than 50% of the predicted ULR is produced back within the first three months of production. Although the intense completion-design strategy for Zipper-1 wells led to 35% larger effective fracture volume compared to Zipper-2 wells, both groups show similar oil recovery performance. Generally, Niobrara wells show less load recovery and effective fracture volume compared to Codell wells in each completion group.
- North America > United States > Colorado (1.00)
- North America > United States > Texas (0.93)