In this study, we propose a new method for estimating average fracture compressibility during flowback process, and apply it on flowback data from thirty multi-fractured horizontal wells completed in Eagle Ford, Horn River, Montney and Woodford formations. We conduct complementary diagnostic flow regime analyses and calculate by combining a flowing material balance equation with rate-decline analysis. We observe two production signatures during flowback: (1) single-phase water production followed by hydrocarbon breakthrough and (2) immediate production of hydrocarbon with water. Water rate-normalizedpressure plots show pronounced unit slopes, suggesting pseudo-steady state flow. Water decline curves follow a harmonic trend during multiphase flow; from which we forecasted ultimate water production as an estimate of initial fracture volume.
We analyzed flowback (FB) and post-flowback (PFB) production data from six multi-fractured horizontal wells completed in Eagle Ford Formation. The wells are supercharged at the beginning of the flowback process and the reservoir pressure remains above bubble point during the post-flowback period. Interestingly, we observe a pronounced unit slope (pseudo-steady state) in the rate-normalized pressure (RNP) plots of water for post-flowback period, while such unit slope is not observed for the flowback period. We developed a conceptual and mathematical model to describe these observations and to estimate the average fracture pore volume (Vf) during the post-flowback process. This model assumes no water influx from matrix into the fracture system, which is consistent with the lack of mobile water in the target reservoir. It also assumes stable influx of oil from matrix into the fracture system with insignificant mass accumulation of oil in the fracture system. Therefore, water production at pseudo-steady state conditions occurs under the driving forces of water expansion, oil expansion, and fracture closure. We also performed decline curve analysis on water production data to estimate initial Vf, as the fractures tend to be fully saturated with water at the beginning of the flowback process. The difference between ultimate water recovery and average Vf from the PFB model represents the loss in fracture volume due to fracture closure. The results show that about 65% of fracture closure occurs after 7 months of PFB production. Fracture closure is the dominant drive mechanism during FB and early PFB periods when reservoir pressure drops rapidly.
Analysis of flowback is becoming a common practice for early characterization of fractured horizontal wells completed in unconventional reservoirs. Several authors have developed different models for analyzing early flowback data to characterize complex fracture networks created by multi-fractured horizontal wells. Examples of recent studies include Abbasi et al. (2012, 2014), Ezulike et al. (2013), Clarkson and Williams-Kovacs (2013), Ezulike and Dehghanpour (2014a, b), Jia et al. (2015), Xu et al. (2016), Ezulike et al. (2016), Yang et al. (2016), Williams-Kovacs (2017) and Chen et al. (2017).
The water recovered from hydraulic-fracturing operations (i.e., flowback water) is highly saline, and can be analyzed for reservoir characterization. Past studies measured ion-concentration data during imbibition experiments to explain the production of saline flowback water. However, the reported laboratory data of ion concentration are approximately three orders of magnitude lower than those reported in the field. It has been hypothesized that the significant surface area created by hydraulic-fracturing operations is one of the primary reasons for the highly saline flowback water.
In this study, we investigate shale/water interactions by measuring the mass of total ion produced (TIP) during water-imbibition experiments. We conduct two sets of imbibition experiments at low-temperature/low-pressure (LT/LP) and high-temperature and high-pressure (HT/HP) conditions. We study the effects of rock surface area (As), temperature, and pressure on TIP during imbibition experiments. Laboratory results indicate that pressure does not have a significant effect on TIP, whereas increasing As and temperature both increase TIP. We use the flowback-chemical data and the laboratory data of ion concentration to estimate the fracture surface area (Af) for two wells completed in the Horn River Basin (HRB), Canada. For both wells, the estimated Af values from LT/LP and HT/HP test results have similar orders of magnitude (approximately 5.0×106 m2) compared with those calculated from production and flowback rate-transient analysis (RTA) (approximately 106 m2). The proposed scaleup procedure can be used as an alternative approach for a quick estimation of Af using early-flowback chemical data.
Soleiman Asl, Taregh (University of Alberta) | Habibi, Ali (University of Alberta) | Ezulike, Obinna Daniel (University of Alberta) | Eghbalvala, Maryam (University of Alberta) | Dehghanpour, Hassan (University of Alberta)
We analyzed flowback and post-flowback production data from a horizontal well in the Montney Formation, which was fractured with water containing a microemulsion additive. This well was shut-in for 7 months after 5 months of post-flowback production. Oil and gas rates were significantly increased after the shut-in (700% increase), suggesting a reduction in matrix-fracture damage. We performed imbibition oil-recovery tests to evaluate the imbibition of the ME solution into the oil-saturated core plugs. The results show that the microemulsion solution can spontaneously imbibe into the oil-saturated core plugs leading to the final oil recovery factor of 24% of the original oil in place, compared with the tap water case with only 2% oil recovery factor. Combined analyses of the field and laboratory results suggest that imbibition of the fracturing water containing the ME solution during the extended shut-in period leads to 1) reduction of water blockage near the fracture face and 2) counter-current production of oil. These two effects can explain the enhanced production rate of oil and gas after the shut-in period.
Hydraulic fracturing combined with horizontal drilling is the key to unlocking vast unconventional reservoirs. However, understanding the relationship between fracturing/completion-design parameters and the process efficiency remains challenging. The objectives of this paper are 1) to estimate initial fracture volume and its variations during the production by using flowback data and 2) to investigate the existence of correlations between completion-design parameters and induced fracture volume process optimization. We analyze flowback data and completion-design parameters of 16 shale-gas completed in the Eagle Ford Formation. First, we estimate ultimate water recovery and initial fracture volume by using harmonic-decline model, and fracture volume loss during flowback by using a new iterative approach that accounts for fracture-porosity changes with time. Then, we conduct a multivariate analysis to develop empirical correlations of completions-design parameters with initial fracture volume and fracture characteristic-closure rate (FCR).
The results show that harmonic-decline model could be used to estimate initial fracture volume with an average absolute percentage error (AAPE) of 7%. The correlations developed between initial fracture volume and completion-design parameters show that the proppant concentration has the most significant effect on fracture volume, followed by gross perforated interval (GPI) and shut-in time, respectively. Total vertical depth (TVD) and fluid injection rate have insignificant effects. The results indicate that increasing choke size during early flowback leads to a relatively-sharp decrease in fracture volume, while changing choke size during late flowback has negligible effects. The proposed correlation between FCR and completion-design parameters demonstrates the significant effect of proppant concentration on fracture closure during flowback, while GPI and TVD have negligible effects.
In this study, we use a custom-designed visual cell to investigate nonequilibrium interactions between liquid propane (C3(1)) and a heavy oil sample (7.2°API) at 55°C. The heavy oil sample is taken from Clearwater Formation located in Western Canadian Sedimentary Basin (WCSB). We inject C3(1) into the visual cell containing the heavy oil sample (pressure buildup process) and allow the injected C3(1) to interact with the oil sample (soaking process). After the pressure buildup process, we observe three phases in the visual cell: 1) heavy oil (0.67 mol), 2) liquid C3 (C3(1),0.60 mol), and gaseous C3 (C3(g), 0.20 mol). We measure visual-cell pressure and observe the C3-heavy oil interactions during the pressure buildup and soaking processes. Nonequilibrium interactions occurring at the interfaces of C3(1)-heavy oil and C3(1)-C3(g) are recorded over time.
The results show that complete mixing of heavy oil with C3(1) occurs in two stages. First, upward extracting flow of hydrocarbon components from bulk heavy oil phase toward C3(1) phase form a distinguished layer (L1) during the soaking process. The extracted oil components become denser over time and move down (draining flows) towards the C3(1)-heavy oil interface due to gravity. The gradual color change of L1 from colorless to black suggests the mixing of hydrocarbon components from heavy oil. After L1 becomes homogenous, a second layer (L2) is formed at the upper part of the bulk C3(1) phase (above L1). Extracting and draining flows becomes active once again, leading to mixing of oil components from L1 into L2. At equilibrium condition, heavy oil and C3(1) are completely mixed and form a single homogenous phase.
The coinjection of carbon dioxide (CO2) or light hydrocarbons with steam in the steam-assisted-gravity-drainage (SAGD) process might enhance bitumen mobility and reduce the steam/oil ratio (SOR). Understanding and modeling the phase behavior of solvent/bitumen systems are essential for the development of in-situ processes for bitumen recovery. In this paper, an experimental and modeling study is undertaken to characterize the phase behavior of bitumen/CO2 and bitumen/C4 systems. Produced and dewatered oil from the Cenovus Osprey Pilot is used for the experiments. The Osprey Pilot produces oil from the Clearwater Formation. Constant-composition-expansion (CCE) experiments are conducted for characterizing Clearwater bitumen, CO2/bitumen mixture, and C4/bitumen mixture. The Peng and Robinson (1978) equation of state (EOS) (PR-EOS) is calibrated using the measured data and is used for pressure/volume/temperature (PVT) modeling. Multiphase equilibrium calculations are performed to predict the solubility of CO2 and C4 in the temperature range of 393.2 to 453.2 K. The potential of asphaltene precipitation for CO2/bitumen and C4/bitumen mixtures is also investigated using three screening criteria.
According to the CCE tests and multiphase equilibrium calculations, C4 has much higher solubility in bitumen than does CO2 at operating pressure of 3997.9 kPa and temperature between 393.2 and 453.2 K (393.2 K < T < 453.2 K). During the CCE tests, coexistence of three equilibrium phases is observed for the C4/bitumen system with high C4 concentration. The three phases consist of a heavy oleic phase (L1), gaseous phase (V), and a light (solvent-rich) oleic phase (L2). Compositional analysis of the samples from L1 and L2 phases shows that C4 can extract light hydrocarbon components from bitumen into the L2 phase and preserve the heavy components in the L1 phase. Also, the L2 phase becomes darker by increasing the pressure, suggesting the extraction of heavier hydrocarbon components at higher pressures. Similar tests on the CO2/bitumen system show only two effective phases over a similar temperature range. The two phases consist of a heavy oleic phase (L1) and a gaseous phase (V).
Phase-equilibrium regions are predicted using the regressed EOS model in the compositional space for the solvent/bitumen system. EOS predictions indicate two types of two-phase regions in the composition space for the C4/bitumen system (i.e., L1/L2 when 393.2 K < T < 421.2 K and L1/V when 421.2 K < T < 453.2 K). However, only one type of two-phase region (i.e., L1/V) exists in a similar temperature range for a CO2/bitumen system. The EOS predictions show that 1.8 wt% CO2 can reduce bitumen viscosity by up to 1.4 times, and 16.3 wt% C4 can reduce bitumen viscosity by up to 20 times when 393.2 K < T < 453.2 K. Viscosity calculations indicate that oil dilution by CO2 and C4 dissolution is more effective at lower temperatures, especially for C4. This shows the potential of injecting hot hydrocarbon solvents for bitumen recovery. The results show that asphaltene might precipitate in a system of C4/bitumen with high C4 concentration.
We conduct this study through the following 3 key steps.
In this study, we use a custom-designed visual cell to investigate nonequilibrium carbon dioxide (CO2)/oil interactions under high-pressure/high-temperature conditions. We visualize the CO2/oil interface and measure the visual-cell pressure over time. We perform five sets of visualization tests. The first three tests aim at investigating interactions of gaseous (g), liquid (l), and supercritical (sc) CO2 with a Montney (MTN) oil sample. In the fourth test, to visualize the interactions in the bulk oil phase, we replace the opaque MTN oil with a translucent Duvernay (DUV) light oil (LO). Finally, we conduct an N2(sc)/oil test to compare the results with those of CO2(sc)/oil test. We also compare the results of nonequilibrium CO2/oil interactions with those obtained from conventional pressure/volume/temperature (PVT) tests.
Results of the first three tests show that oil immediately expands upon injection of CO2 into the visual cell. CO2(sc) leads to the maximum oil expansion followed by CO2(l) and CO2(g). Furthermore, the rate of oil expansion in the CO2(sc)/oil test is higher than that in CO2(l)/oil and CO2(g)/oil tests. We also observe extracting and condensing flows at the CO2(l)/oil and CO2(sc)/oil interfaces. Moreover, we observe density-driven fingers inside the LO phase because of the local increase in the density of LO. The results of PVT tests show that the density of the CO2/oil mixture is higher than that of the CO2-free oil, explaining the density-driven natural convection during CO2(sc) injection into the visual cell. We do not observe either extracting/condensing flows or density-driven mixing for the N2(sc)/oil test, explaining the low expansion of oil in this test. The results suggest that the combination of density-driven natural convection and extracting/condensing flows enhances CO2(sc) dissolution into the oil phase, leading to fast oil expansion after CO2(sc) injection into the visual cell.
In this study, we evaluate the wettability of shale plugs from the Duvernay Formation, which is a self-sourced reservoir in the Western Canadian Sedimentary Basin. We use reservoir oil and flowback water (brine) to conduct air/liquid contact-angle and air/liquid spontaneous-imbibition tests for wettability evaluation. We characterize the shale samples by measuring pressure-decay permeability, effective porosity, initial oil and water saturations, mineralogy, and total-organic-carbon (TOC) content, and by conducting rock-eval pyrolysis tests. We also conduct scanning-electron-microscope (SEM) and energy-dispersive X-ray spectroscopy (EDS) analyses on the shale samples to characterize the location and size of pores. After evaluation of wettability, we conduct soaking tests. First, we measure liquid/liquid contact angles for the droplets of the soaking fluids and reservoir oil equilibrated on the surface of the oil-saturated plugs. Then, we conduct soaking tests by immersing the oil-saturated plugs in different soaking fluids, and record the oil volume produced from spontaneous imbibition of the soaking fluids. The soaking fluids are characterized by measuring surface tension (ST), interfacial tension (IFT), viscosity, and pH. We analyze the results of soaking tests and investigate the controlling parameters affecting oil recovery factor (RF).
The results demonstrate that the shale samples have stronger wetting affinity toward oil compared with brine. The positive correlations of TOC content with effective porosity and pressure-decay permeability suggest that the majority of connected pores are within the organic matter. The strong oil-wetness of the shale samples can be explained by the abundance of organic porosity, verified by the SEM/EDS images. The results of liquid/liquid contact-angle tests show that the soaking fluid with lower IFT exhibits a stronger wetting affinity toward the shale. The results also show that oil RF is higher for the soaking fluids with lower IFT, which may be caused by wettability alteration. In addition, comparing the results of air/brine imbibition with those of the soaking tests indicates that adding nonionic surfactant to the soaking fluid may alter the wettability of hydrophobic organic pores toward less-oil-wet conditions, leading to the displacement of oil from organic pores.