Flowback data from seven multifractured horizontal tight oil/gas wells in Anadarko Basin show two separate regions during the single-phase water production. Region 1 shows a dropping casing pressure, and Region 2 shows a flattening casing pressure. This paper investigates the flowback behavior of the two regions, and illustrates how flowback data can be interpreted to estimate effective fracture pore volume, and to investigate its relationship to completion-design parameters. We construct diagnostic plots to understand the physics of Regions 1 and 2. Region 1 represents pressure depletion in fractures, and Region 2 represents the hydrocarbon breakthrough into the effective fracture network. The results of our analyses indicate that the duration of Region 1 depends on initial reservoir pressure and hydrocarbon type. We apply a previous flowback model (Abbasi et al. 2012, 2014) on Region 1 to estimate effective fracture pore volume, and also propose a procedure to estimate fracture compressibility by use of diagnostic-fracturing-injection-test (DFIT) data. The results suggest that the estimated effective fracture pore volume is very sensitive to fracture compressibility, and is generally larger than the final load-recovery volume, and less than the total injected-water volume. The results also suggest that most of the effective fractures are unpropped, and host the nonrecovered fracturing water. We investigate the relationship between the estimated effective fracture pore volumes and completion-design parameters, including total injected-water volume, proppant mass, gross perforated interval, and number of clusters, by use of the Pearson correlation-coefficient method. The results show that total injected-water volume, gross perforated interval, and the number of clusters are among the key design parameters for an optimal fracturing treatment. Higher total injected-water volume and closer cluster spacing generally lead to a larger effective fracture pore volume.
Co-injection of CO2 or light hydrocarbons with steam in SAGD (Steam Assisted Gravity Drainage) process may enhance bitumen mobility and reduce Steam Oil Ratio (SOR). Understanding and modeling the phase behavior of solvent-bitumen system 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-Robinson equation of state (PR-EOS) is calibrated based on the measured data and used for PVT modeling. Multiphase equilibrium calculations are performed to predict the solubility of CO2 and C4 in the temperature range of 120 °C to180 °C. Further to that, dead oil viscosity measurements are conducted at similar temperature intervals to estimate oleic phase viscosity.
According to the CCE tests and multiphase equilibrium calculations, C4 has much higher solubility in bitumen than CO2 at reservoir pressure of 580 psia (4,000 kpa) and temperature range of 120 °C to 180 °C. During the CCE tests, co-existence of three equilibrium phases is observed for the C4-bitumen system with 84 wt.% C4. The three phases consist of a solvent-lean (bitumen-rich) oleic phase (L1), gaseous phase (V) and a solvent-rich (bitumen-lean) oleic phase (L2). Compositional analysis of the samples from L1 and L2 phases shows that C4 can extract light hydrocarbon components from bitumen into L2 phase and preserve the heavy components in L1 phase. It is observed that the color of L2 phase becomes lighter by decreasing the pressure which may suggest extraction of lighter hydrocarbon components at lower pressures. Similar tests on the CO2-bitumen system only shows two effective phases over a similar temperature range. The two phases consist of a solvent-lean (bitumen-rich) oleic phase (L1) and a gaseous phase (V).
By using the regressed EOS model, phase equilibrium regions are predicted in the compositional space for the solvent-bitumen system. EOS predictions indicate two types of two-phase regions in composition space for C4-bitumen system (i.e., L1-L2 in temperature range of 120 °C to 148 °C and L1-V in temperature range of 148 °C to180 °C). However, only one type of two-phase region (i.e., L1-V) exists in the similar temperature range for CO2-bitumen system. The EOS predictions show that 1.7 wt.% CO2 can reduce bitumen viscosity by up to 4 times, and 8.7 wt.% C4 can reduce bitumen viscosity by up to 32 times in temperature range of 120 °C to 180 °C.
In this study, we use a custom-designed visual cell to investigate non-equilibrium CO2/oil interactions under high-pressure and high-temperature conditions. We visualize the CO2/oil interface and measure visual cell's pressure over time. We perform 5 sets of visualization test. The first three tests aim at investigating interactions of gaseous (g), liquid (l), and supercritical (sc) CO2 with the Montney oil. In the fourth test, in order to visualize the interactions at the bulk oil phase, we replace the opaque Montney oil with a translucent Duvernay light oil (LO). Finally, we conduct N2(sc)-Oil test to compare the results with those of CO2-Oil 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 CO2l and CO2(g). Furthermore, the rate of oil expansion in 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 due to the local increase in the density of LO. We do not observe neither extracting/condensing flows nor density-driven mixing for N2(sc)-Oil and CO2(g)-Oil tests, explaining low expansion of oil in these tests. The results suggest that the combination of density-driven natural mixing and extracting/condensing flows enhance CO2(sc) dissolution into the oil phase, leading to fast oil expansion after CO2(sc) injection into the visual cell.
This study presents a workflow for identifying and evaluating well interference, and investigating how interference affects fracture cleanup in a multi-well pad.
We analyze flowback pressure and tracer data from a 10-well pad completed in three shale members of the Horn River Basin. Three key steps are used in this study: First, we analyze the tracer concentration profiles to investigate well interference in the pad before flowback. Second, we compare the casing pressure of the wells during selective shut-in and re-opening to investigate well interference during flowback and post-flowback periods. Third, we construct diagnostic plots of gas-water ratio (GWR) to see how well interference affects fracture cleanup during flowback.
We observe that well interference in the pad occurs in three stages – before flowback, during flowback and during post-flowback. Before flowback, concentration profiles from some wells show early breakthrough of tracers injected into neighboring wells in the pad. Analysis of the tracer data suggests that fracturing operations create connecting pathways among the wells in the pad. During flowback and post-flowback, we observe that the shut-in and re-opening of some wells in the pad disturb the recorded pressure in the remaining wells. The log-log plots of GWR versus cumulative gas production for late-opened wells show an approximate half-slope, suggesting fracture cleanup. However, this trend of fracture cleanup is not observed for the early-opened wells. This shows that the early-opened wells drain fracturing water from the late-opened wells through connected fractures, when the wells in a pad are opened for flowback in a sequence. Combined analysis of flowback and tracer data helps to understand how fracturing water migrates between wells, and to optimize well placement in a pad.
“Frac-hit” is a common phenomenon when multi-fractured horizontal wells are tightly spaced in an unconventional reservoir. Frac-hit is a rapid pressure increase in wells that are shut-in during the fracturing treatment of offset wells. Well interference during fracturing operations has been identified and evaluated using the pressure increase during frac-hit (Sardinha et al. 2014; Lehmann et al. 2016). However, it is not clear if the well interference caused by frac-hit is sustained after fracturing treatment, and how it affects hydrocarbon production.
Zolfaghari, Ashkan (University of Alberta) | Tang, Yingzhe (University of Alberta) | He, Jia (University of Alberta) | Dehghanpour, Hassan (University of Alberta) | Bearinger, Doug (Nexen Energy ULC) | Virues, Claudio (Nexen Energy ULC)
As observed in many shale-gas plays, the produced flowback water is highly saline and the salt concentration increases with time. Several past studies investigated water-rock interactions to interpret flowback chemical data, evaluate reservoir performance, and investigate the environmental impacts of fracturing operations. In this study, we measure the total ion produced (
In order to investigate the effect of
Imbibition of water into the shale matrix is known as the primary reason for inefficient water recovery after hydraulic fracturing treatments. The hydration of clay minerals may induce microfractures in clay-rich shale samples. The increased porosity and permeability due to induced microfractures has been considered to be partly responsible for 1) excessive water uptake of gas shales, and 2) increase in hydrocarbon production rate after prolonged shut-in periods. To test this hypothesis, it is necessary to measure imbibition-induced strain and stress under representative laboratory conditions.
In this study, we conduct laboratory tests to 1) measure the strain and stress induced by water imbibition in gas shales and 2) investigate the effect of confining load on the rate of water imbibition. We conduct a three-phase study on rock samples from the Horn River Basin (HRB) and the Duvernay (DUV) Formation, located in the Western Canadian Sedimentary Basin. In the first phase, we measure baselines for water and kerosene imbibition into the rock samples by conducting spontaneous imbibition tests. In the second phase, we measure expansion of the rock samples during imbibition of water and kerosene, in separate tests, using a linear variable differential transformer (LVDT). In the third phase, we measure imbibition-induced tensile stress during water imbibition into the samples.
The results show that both HRB and DUV shale samples imbibe more water than kerosene, due to water adsorption by clay minerals. Imbibition of water increases the porosity of the HRB and the DUV samples by up to 0.94 and 0.25 percentage points, respectively. Expansion of all samples is anisotropic, with higher expansion perpendicular to the depositional lamination. Water imbibition into the samples induces an expansive stress as high as 17 psi. Moreover, applying confining stress reduces the imbibition of water by up to 18.1% and 33.7% in the HRB and DUV samples, respectively.
In this study, we evaluate the wettability of shale samples drilled in the Duvernay Formation, which is a source-rock reservoir located in the Western Canadian Sedimentary Basin (WCSB). We use reservoir oil and brine to conduct air-liquid contact angle and air-liquid spontaneous imbibition tests for wettability measurements. We characterize the shale samples by measuring pressure-decay permeability, effective porosity, initial oil and water saturations, mineralogy, total organic carbon (TOC) content, and 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 experiments. First, we measure liquid-liquid contact angles for the droplets of the soaking fluids and reservoir oil equilibrated on surface of the rock samples. Then, we immerse the oil-saturated samples in the soaking fluids with different compositions and physical properties. The we record the oil volume produced due to spontaneous imbibition of the soaking fluids. The soaking fluids are characterized by measuring surface tension, interfacial tension (IFT), viscosity, and pH. We analyze the results of soaking tests and investigate the controlling parameters affecting oil recover factor (RF).
The results of wettability measurements demonstrate that the shale samples have stronger wetting affinity to 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 present within the organic matter. Organic porosity may explain the strong oil-wetness of the shale samples. The SEM/EDS analyses also show the abundance of organic nanopores within organic matter. The results of liquid-liquid contact angle tests show that a reduction in IFT of the soaking fluid leads to an increase in wetting affinity of rock to soaking fluid. The results also show that oil RF is higher for soaking fluids with lower IFT, which can be explained by wettability alteration. The shale samples have higher wetting affinity to soaking fluids with lower IFT, leading to an increase in the driving capillary pressure and, consequently to higher oil recovery by spontaneous imbibition. In addition, comparing the results of air-brine imbibition with soaking tests suggests that adding surfactant to the soaking fluid may alter the wettability of organic pores towards more water-wetness, leading to the displacement of oil from hydrophobic organic pores.
Previous studies demonstrate that the Montney rock samples have a dual-wettability pore network. Recovery of the oil retained in the small hydrophobic pores is a unique challenge. In this study, we apply dual-core imbibition (DCI) method on several Montney core plugs and introduce imbibition-recovery (IR) trio to investigate the recovery mechanisms in rocks with dual-wettability pore network. First, we evaluate the wetting affinity of five twin core-plugs from the Montney Formation by measuring spontaneous imbibition of reservoir oil and brine, and by measuring equilibrium contact angle. We place one plug of each pair in the oil and the other in the brine, and measure the weight change periodically. Second, we place the oil-saturated samples in the brine to visualize the expelled oil droplets and measure volume of the recovered oil. We comparatively analyze the spontaneous imbibition data from the first step and the recovery data of the second step in one imbibition-recovery trio (oil imbibition, brine imbibition, and imbibition oil recovery). The results of air-liquid contact angle and spontaneous imbibition on dry samples suggest that the affinity of the samples to oil is higher than that to brine, in an air-liquid system. However, the results of liquid-liquid contact angle and counter-current imbibition tests suggest that the affinity of the samples to water is higher than that to oil, in a liquid-liquid system. For each twin set, the oil recovery curve follows the trend of brine imbibition curve, and the final oil recovery is always less than the equilibrated water uptake of dry samples. This observation indicates that water can only access the hydrophilic part of the pore network initially saturated with oil. Finally, we introduce a porosity-based model to analyze oil-recovery data.
This paper presents comprehensive rock-fluid experiments to study the possibility of oil recovery improvement when CO2 is injected as a fracturing fluid in the Montney tight-oil play, located in the Western Canadian Sedimentary Basin. This study consists of four phases: In phase 1, we conduct constant composition expansion (CCE) tests with different CO2 concentrations using a PVT cell. In phase 2, we visualize CO2-oil interactions at reservoir pressure and temperature in a custom-designed visual cell. Then, we conduct SEM/EDS analysis on the solid precipitates in the visual cell due to CO2-oil interactions. In phase 3, we soak the oil-saturated core plugs in the visual cell, pressurize the cell with CO2, and measure the oil recovery. In phase 4, we conduct cyclic CO2 tests using a core flooding system, and measure the oil recovery. We also evaluate the oil viscosity and wettability of the core plugs before and after cyclic CO2 process.
The results of the CCE tests conducted using the PVT cell and visualization tests conducted using the visual cell show that CO2 can significantly dissolve into and expand the Montney oil. The results of the CO2 soaking tests and cyclic CO2 process show that the oil swelling due to CO2-oil interactions results in high oil recovery factor from the oil-saturated core plugs. In addition, we observe solid precipitates due to CO2-oil interactions at the bulk-phase conditions in the visual cell. SEM/EDS analysis on the solid precipitates show the existence of carbon and sulfur, the main components of asphaltene. The results of IP-143 test confirm the formation asphaltene when the Montney oil contacts CO2 at reservoir conditions.
Recent studies show that the pore network of unconventional rocks, such as gas shales, generally consists of inorganic and organic parts. The organic part is strongly oil-wet and preferentially imbibes the oleic phase. In contrast, the inorganic part is usually hydrophilic and preferentially imbibes the aqueous phase. Conventional theories of relative permeability, which are based on uniform wettability, cannot be applied to determine phase permeability in unconventional rocks with dual-wettability behavior. The objective of this paper is to extend the previous theories to model relative permeability of dual-wettability systems in which oleic and aqueous phases can both act as wetting phases in hydrophobic and hydrophilic pore networks, respectively.
In the first part of the paper, we review and discuss the results of scanning electron microscopy (SEM), organic petrography, mercury injection capillary pressure (MICP), and comparative water/oil imbibition experiments conducted on several samples from the Triassic Montney tight gas siltstone play of the Western Canadian Sedimentary Basin. We also discuss various crossplots to understand the reasons behind the observed dual-wettability behavior, and to investigate the spatial distribution and morphology of hydrophilic and hydrophobic pores. In the second part, Purcell’s model (Purcell 1949) is extended to develop a conceptual model for relative permeability of gas and water in a dual-wettability system such as the Montney tight gas formation. Finally, the proposed model is compared with measured relative permeability data.
The results suggest that the submicron pores within solid bitumen/pyrobitumen are strongly water-repellant; therefore, they prefer gas over water under different saturation conditions. This part of the pore network is usually represented by a long tail at the lower end of the pore-throat-size distribution determined from MICP. The proposed relative permeability model describes single-phase flow of gas through the tail part, and two-phase flow of gas and water through the remaining bell-shaped part of the pore-throat-size distribution, which dominantly represents inorganic micropores. On the basis of our model, by increasing the fraction of water-repellant submicron pores, gas relative permeability decreases for a fixed water saturation. This decrease is ascribed to the reduction of the average size of flow conduits for the gas phase.