Hassan Dehghanpour

Understanding Flowback as a Transient 2-Phase Displacement Process: An Extension of the Linear Dual-Porosity Model

Existing rate transient models for fractured horizontal wells assume single-phase fluid flow. This assumption is violated in early times, when hydraulic fractures (HF) are filled with fracturing water and hydrocarbon. This calls for a model that captures the transient 2-phase (gas/oil + water) flow in HF, and can be used for history matching rate and pressure data measured during flowback operations. Existing models for analysing multiphase data from solution-gas drive and high-water-saturation conventional reservoirs cannot be applied to flowback data because of simplifying assumptions such as (1) constant average phase saturation with time, (2) constant rate or pressure well constraint and (3) radial flow. This paper extends the existing linear dual-porosity model (dPm) and develops a flowback analysis model (FAm) which accounts for transient multiphase flow in HF. The proposed model adopts an explicit dynamic-relative-permeability (dRP) function of time for hydrocarbon phase in the fracture network to account for water-saturation drop. This model assumes that water-saturation drop with time causes a corresponding non-linear increase in hydrocarbon relative-permeability in HF. The dRP function is obtained from analysing cumulative hydrocarbon + water measured during flowback operation and drainage relative-permeability curves from existing literature. Fifteen tight oil, tight gas and shale gas wells completed in the bluesky, Cardium, Evie, muskwa and otter-Park Formations were used for this study. The resulting dRP parameters control the rate of water-saturation drop in HF (clean-up rate). dRP is incorporated into the existing dPm to obtain FAm flow equations. This paper attempt solving these equations with mellin transforms under variable bottomhole rate and pressure well constraints. FAm converges to the existing dPm at the limit of residual water-saturation. dRP captures the fluid physics from flowback phase till the “full” hydrocarbon production phase in the life of a multifractured horizontal well. The application of FAm on transient 2-phase flowback data (rate + pressure) could help estimate key reservoir parameters (e.g. effective HF half-length) and evaluate flowback performance (e.g. percentage of total inject fluid left in HF and matrix and the speed of HF clean-up). Results from this study is applicable for interpreting 2-phase flowback data from multifractured horizontal wells completed in tight and shale reservoirs. This study allows the industry to forecast hydrocarbon recovery from flowback data and estimate/predict the effectiveness of flowback operations. To order the full paper, visit https://www.onepetro.org/conference-paper/SPE-167164-MS

Tight Rock Wettability and Its Relationship to Other Petrophysical Properties: A Montney Case Study

Understanding and modelling the wettability of tight rocks is essential for designing fracturing and treatment fluids. In this paper, we measure and analyze spontaneous imbibition of water and oil into five twin core plugs drilled from the cores of a well drilled in the Montney Formation, an unconventional oil and gas play in the Western Canadian Sedimentary Basin. We characterize the samples by measuring the mineralogy using XRD (x-ray diffraction), total organic carbon content, porosity, and permeability. Interestingly, the equilibrated water uptake of the five samples is similar, while, their oil uptake increases by increasing the core porosity and permeability. We define two wetta-bility indices for the oil phase based on the slope and equilibrium values of water and oil imbibition curves. Both indices increase by increasing porosity and permeability, with the slope affinity index showing a stronger correlation. This observation suggests that part of the pore network has a stronger affinity to oil than to water. We also observe that the two indices decrease by increasing neutron porosity and gamma ray parameters measured by wireline logging tools. The samples with higher gamma ray and neutron porosity are expected to have greater clay content, and thus less effective porosity and permeability.

Flowback Fracture Closure: A Key Factor for Estimating Effective Pore Volume

The importance of evaluating well productivity after hydraulic fracturing can not be overemphasized. This has necessitated the improvement in the quality of rate and pressure measurements during flowback of multistage fractured wells. Similarly, there has been corresponding improvements in the ability of existing transient models to interpret multiphase flowback data. However, the complexity of these models introduces high uncertainty in the estimates of resulting parameters such as fracture pore-volume, half-length and permeability. This paper proposes a two-phase tank model for reducing parameter uncertainty and estimating fracture pore-volume independent of fracture geometry. This study starts by using rate-normalized pressure plots to observe changes in fluid flow mechanisms from multistage fractured wells. The fracture “pressure supercharge” observations form the basis for developing the proposed two-phase tank model. This model is a linear relationship between rate normalized pressure and time, useful for interpreting flowback data in wells which show pseudo steady-state behavior (unit slope on log-log rate normalized-pressure plots). The linear relationship is implemented on a simple montecarlo spreadsheet. This is then used to estimate and conduct uncertainty analysis on effective fracture pore-volume, using probabilistic distributions of average fracture compressibility, and gas/water saturations respectively. Also, the proposed model investigates the contributions of various drive mechanisms during flowback including fracture closure, gas expansion and water depletion. Application of the proposed tank model to flowback data from fifteen shale gas and tight oil wells estimates the effective fracture porevolume and initial average gas saturation in the active fracture network. The results show that fracture pore-volume is most sensitive to fracture closure compared to gas expansion and water depletion, making fracture closure the primary drive mechanism during early flowback periods. Also, the initial average gas saturation for all wells is less than twenty percent. The parameters estimated from the proposed model could be used as input guides for more complex studies (such as discrete fracture network modeling and transient flowback simulation). This reduces the number of unknown parameters and uncertainty in output results from complex models.. To order the full paper, visit https://doi.org/10.2118/175143-MS TECHNICAL PAPER

Fractional Flow Approach to Saturation Overshoot

Saturation overshoot is observed for 1D vertical infiltrations (liquid replacing gas) in many porous media. Aspects of these infiltrations are often described using the Richards equation, which assumes that the gas viscosity is negligible compared to the liquid viscosity. Here, we develop a multi-phase, fractional flow approach to describe the physics behind the displacement front that includes the viscosity of the gas. We show that an overshoot profile will draw in gas behind the overshoot tip. We compare the fractional flow solution to the Richards equation solution and to experimental data, and show that the air viscosity plays an observable role when the infiltrating flux is greater than 50% of the saturated conductivity.

Drainage of Capillary-Trapped Oil by an Immiscible Gas: Impact of Transient and Steady-State Water Displacement on Three-Phase Oil Permeability

In a previous paper (Dehghanpour et al., Phys Rev E 83:065302, 2011a), we showed that relative permeability of mobilized oil,

A Flowback-Guided Approach for Production Data Analysis in Tight Reservoirs

k_\mathrm{ro}

Liquid Intake of Organic Shales

kro, measured during tertiary gravity drainage, is significantly higher than that of the same oil saturation in other tests where oil is initially a continuous phase. We also showed that tertiary