Search

Summary We propose a novel method for estimating average fracture compressibility cf¯ during flowback process and apply it to flowback data from 10 multifractured horizontal wells completed in Woodford (WF) and Meramec (MM) formations. We conduct complementary diagnostic flow-regime analyses and calculate cf¯ by combining a flowing-material-balance (FMB) equation with pressure-normalized-rate (PNR)-decline analysis. Flowback data of these wells show up to 2 weeks of single-phase water production followed by hydrocarbon breakthrough. Plots of water-rate-normalized pressure and its derivative show pronounced unit slopes, suggesting boundary-dominated flow (BDF) of water in fractures during single-phase flow. Water PNR decline curves follow a harmonic trend during single-phase- and multiphase-flow periods. Ultimate water production from the forecasted harmonic trend gives an estimate of initial fracture volume. The cf¯ estimates for these wells are verified by comparing them with the ones from the Aguilera (1999) type curves for natural fractures and experimental data. The results show that our cf¯ estimates (4 to 22×10−5 psi−1) are close to the lower limit of the values estimated by previous studies, which can be explained by the presence of proppants in hydraulic fractures.

Summary 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.

The inter-salt argillaceous dolomite reservoirs in the central region of China contain large abundance of oil resources with ultra-low permeability and porosity. However, the oil wells in this area show a very quick reduction with the decline of formation pressure. This article aims to investigate the main possible reasons that affect oil well productivity in the target oilfield. This study begins with analysis of capillary microscopic model, core stress sensitivity experiments, and non-Darcy percolation experiments. The impact of effective stress on permeability and porosity of the reservoir was revealed in this article. The novel productivity model and productivity evaluation model which couples stress sensitivity and threshold pressure gradient were proposed. The analysis of capillary microscopic model shows stress sensitivity of permeability to be much greater than that of porosity during the process of depressurization. The core stress sensitivity experiments results indicate that permeability and effective stress show index relationship while porosity and effective stress show binomial relationship. Damage rate and recovery rate of permeability and porosity were put forward to describe the degree of influence of stress sensitivity on permeability and porosity. The models were used to investigate the factors that affect single well productivity for the target oilfield. Application of the proposed model to this tight oilfield indicates that, the degree of influence of stress sensitivity is much greater than that of threshold pressure gradient. In addition, the greater the stress sensitivity coefficient and threshold pressure gradient are, the greater the productivity reduction will be.

In this study, we propose a new method for estimating average fracture compressibility (cf¯) 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 cf¯ 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-normalized-pressure 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. The cf¯ estimates are within the range of 7 – 200 × 10-6 psi-1, and are generally lower than the values previously estimated using Aguilera’s type curves and DFIT data. Also, cf¯ estimates for deeper dry gas wells are relatively higher than those for shallower oil wells.

Hydraulic fracturing combined with horizontal drilling is the key to unlocking vast unconventional reservoirs. However, understanding the relationship between completion-design parameters (CDPs) and fracturing efficiency remains challenging. The objective of this paper is analyzing flowback data to 1) evaluate the change in effective fracture volume (Vef), and 2) investigate the existence of correlations between CDPs and Vef. We analyze flowback data and CDPs of 22 gas and oil wells completed in the Eagle Ford formation. First, we estimate ultimate water recovery and initial effective fracture volume ( V ef i ) using harmonic-decline (HD) model. Second, we estimate the loss in Vef ( V loss ) during flowback using a new iterative approach that accounts for dynamic fracture porosity and compressibility. Third, we introduce a new parameter to characterize fracture closure rate (FCR) during flowback. FCR represents how fast Vef shrinks during flowback. Then, we present a dimensionless type curve to evaluate FCR and investigate its correlation with CDPs. Finally, we conduct a multivariate analysis to correlate CDPs with V ef i and FCR. The developed correlation between V ef i and CDPs shows that the gross perforated interval (GPI) has the most significant effect on V ef i . The proposed correlation between FCR and CDPs demonstrates the significant effect of proppant concentration on fracture closure during flowback.

The potential environmental impact of hydraulic fracturing is a significant public concern. A key question is: How far can fractures go beyond the well? We analyze microseismic, pressure interaction (frac-hit and interference), and tracer data recorded during fracturing of and production from 52 wells in the Horn River Basin. The results show that the wells communicate through fracture-like pathways which allow water, gas, and proppant flow. The lateral and vertical well communications occur at distances above 1 km and up to 130 m, respectively. Well communication may last for over 1.7 years possibly due to proppant flow, which prevents complete fracture closure during flowback and post-flowback processes.

Shale oil is a key resource that could mitigate the impending energy shortage in the future. Despite its abundance in China, studies on shale oil are still at the preliminary stage. Shale oil development through CO2 flooding has been successfully implemented in the United States. Therefore, the mechanics of CO2 flooding in shale oil reservoirs should be investigated. This study applies a simulation method to evaluate the development efficiency of CO2 flooding in shale oil reservoirs. Near-miscible CO2 flooding can effectively develop shale oil. After 20 years, recovery could improve by up to 9.56% as a result of depletion development under near-miscible CO2 flooding with 0.5% pore volume gas injection. Horizontal well injection is better than vertical well injection in terms of sweep efficiency and recovery. Cyclic gas injection is superior to continuous gas injection because the former reduces gas channelling. Thus, the use of horizontal wells with near-miscible cyclic gas injections has the potential to effectively develop shale oil reservoirs.

This paper establishes a drainage data-based calculation method for coalbed permeability. The method combines material balance and production equations. We use a material balance equation to derive the average pressure of the coalbed in the production process. The dimensionless water production index is introduced into the production equation for the water production stage. In the subsequent stage, which uses both gas and water, the gas and water production ratio is introduced to eliminate the effect of flush-flow radius, skin factor, and other uncertain factors in the calculation of coalbed methane permeability. The relationship between permeability and surface cumulative liquid production can be described as a single-variable cubic equation by derivation. The trend shows that the permeability initially declines and then increases after ten wells in the southern Qinshui coalbed methane field. The results show an exponential relationship between permeability and cumulative water production. The relationship between permeability and cumulative gas production is represented by a linear curve and that between permeability and surface cumulative liquid production is represented by a cubic polynomial curve. The regression result of the permeability and surface cumulative liquid production agrees with the theoretical mathematical relationship.

Flowback data analysis has been recently considered by the industry to quantify hydraulic fracture parameters such as, effective fracture pore-volume. Tools based on simulation and rate transient analysis have been applied for flowback analysis. However, too many unknown parameters, together with complex production mechanisms lead to uncertain and non-unique results. This paper illustrates how flowback data can be interpreted to estimate effective fracture pore-volume and its relationship to fracture design parameters. This study starts by addressing some limitations of the previous flowback models. In particular, the effects of water expansion and fracture closure are included in the proposed model. The resulting linear relationship is applied to flowback data from eight tight oil and gas wells in Anadarko Basin to estimate effective fracture pore-volume. The estimated effective fracture pore-volumes are compared with fracture design parameters such as total injected volume of water, soaking time, gross perforated interval, and proppant concentration. The results indicate that fracture closure is the main mechanism for single-phase water flowback. Therefore, effective fracture pore-volume largely depends on fracture compressibility. The results also show that soaking time, gross perforated index, and proppant concentration are among the key design parameters for an optimum fracturing treatment.

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.