Flowback Analysis for Fracture Characterization

Abbasi, Majid; Dehghanpour, Hassan; Hawkes, Robert

doi:10.2118/162661-ms

Cited by 53 publications

(21 citation statements)

References 6 publications

(3 reference statements)

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“…Unfortunately, shale-gas researchers have not compared simulation models with analytical solutions (Alkouh et al 2012). In this work, simulation is used to verify the new method of analyzing water data using PDA.…”

Section: Literature Reviewmentioning

confidence: 99%

Estimation of Effective-Fracture Volume Using Water-Flowback and Production Data for Shale-Gas Wells

Alkouh

McKetta²,

Wattenbarger

2014

Journal of Canadian Petroleum Technology

100

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Primarily, gas-production data are the main tool used to analyze shale-gas reservoirs. Water production is not usually included in the analysis. In this paper, post-fracturing water flowback and long-term water production are added to the analysis. The water data are usually available but are analyzed separately and not combined with long-term gas-production data. In this paper, procedures and examples are presented, including water-flowback and water-production data, in the analysis of shale-gas wells using rate transient analysis.A number of simulation cases were run. Various physical assumptions were used for the saturations and properties that exist in the fracture/matrix system after hydraulic fracturing. Water flowback and long-term production periods were then simulated. The results of these simulations were compared with data from actual wells by use of diagnostic and specialized plots. These comparisons led to certain conclusions which describe well/reservoir conditions after hydraulic fracturing and during production.This paper shows the benefits of a new method for combining water-flowback and long-term water-production data in shale-gas analysis. Water-production analysis can provide effective-fracture volume which was confirmed by the cumulative produced water. This can help when evaluating fracture-stimulation jobs. It also shows some pitfalls of ignoring flowback data. In some cases, the time shift on diagnostic plots changes the apparent flow-regime identification of the early gas-production data as well as waterproduction data. This leads to different models of the fracture/ matrix system. The presented work shows the importance of including water-flowback data in the long-term production analysis. IntroductionWater production is usually ignored when analyzing and forecasting shale-gas-well performance. The process involves pumping thousands of barrels of water with proppant and additives into the rock at high pressure. Numerous operators along with Wattenbarger and Alkouh (2013) have indicated that the percent of injected fluid recovered (load recovery) in shale-gas wells ranges from 10 to 40%. Flowback is the early data (water/gas rate and pressure) gathered after fracture stimulation of the well, which might be followed by a shut-in. The flow sequence of the usual shale well is presented in Fig. 1 where there is a shut-in period between flowback and production because delays in the pipeline connection. Most operators ignore flowback data and do not combine it with production data.The paper has four main parts: (1) a review of the literature related to flow-regime identification and the diffusivity equation, (2) verification of the new method with a simulated model, (3)

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Section: Literature Reviewmentioning

confidence: 99%

Estimation of Effective-Fracture Volume Using Water-Flowback and Production Data for Shale-Gas Wells

Alkouh

McKetta²,

Wattenbarger

2014

Journal of Canadian Petroleum Technology

100

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“…Recently, two rate transient models (linear + radial) were proposed (Abbasi et al, 2012;Abbasi, 2013) for analysing the early-time portion of flowback and estimating lumped fracture parameters (e.g. The drawback of the RPI method include the (1) assumption of single-phase flow in a homogeneous (conventional) reservoirs and (2) restriction to stimulated vertical wells (not horizontal wells).…”

Section: Spe 167164mentioning

confidence: 99%

“…The drawback of the RPI method include the (1) assumption of single-phase flow in a homogeneous (conventional) reservoirs and (2) restriction to stimulated vertical wells (not horizontal wells). The limitation of these models (Abbasi et al (2012); Abbasi (2013); Clarkson (2012)) is the assumption of pseudosteady fluid depletion in HF which should restrict their application to the short fracture-storage flowback period. porosity and permeability).…”

Section: Spe 167164mentioning

confidence: 99%

“…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. Recently, two rate transient models (linear + radial) were proposed (Abbasi et al, 2012;Abbasi, 2013) for analysing the early-time portion of flowback and estimating lumped fracture parameters (e.g. DRP is incorporated into the existing DPM to obtain FAM flow equations.…”

mentioning

confidence: 99%

“…DRP is incorporated into the existing DPM to obtain FAM flow equations. The limitation of these models (Abbasi et al (2012); Abbasi (2013); Clarkson (2012)) is the assumption of pseudosteady fluid depletion in HF which should restrict their application to the short fracture-storage flowback period. DRP captures the fluid physics from flowback phase till the "full" hydrocarbon production phase in the life of a multifractured horizontal well.…”

mentioning

confidence: 99%

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

Ezulike

Dehghanpour

Hawkes³

2013

All Days

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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 bottom-hole 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 multi-fractured 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. SPE 167164Careful management of flowback procedure is crucial to (1) obtain accurate physical and chemical data measurements and (2) prevent damage to the stimulated well (Crafton, 2008(Crafton, , 2010 and (3) improve well clean-p and maximize load recovery (Crafton, 1998). Accurate data ensures representative flowback volumetric, rate + pressure transient, and chemical analyses. These analyses provide (1) important well and reservoir informat...

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A semi‐analytical model for capturing dynamic behavior of hydraulic fractures during flowback period in tight oil reservoir

Jia

Cheng

et al. 2020

Energy Science & Engineering

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Development of tight oil reservoir relies on multistage fracturing techniques, which inject the compressed fluid to create hydraulic fractures, communicating with natural fractures, and forming complex fracture networks around the wellbore. Many previous experimental research and theoretical analysis have shown that hydraulic fracturing can form a variety of fracture network under different conditions. 1,2 The characteristics of the fracture network formed by hydraulic fracturing directly affect the production performance of the horizontal wells. Therefore, accurately describing the characteristics

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Flowback Analysis for Fracture Characterization

Cited by 53 publications

References 6 publications

Estimation of Effective-Fracture Volume Using Water-Flowback and Production Data for Shale-Gas Wells

Estimation of Effective-Fracture Volume Using Water-Flowback and Production Data for Shale-Gas Wells

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

A semi‐analytical model for capturing dynamic behavior of hydraulic fractures during flowback period in tight oil reservoir

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