Rate-transient analysis of 2-phase (gas + water) CBM wells

Clarkson, Christopher R.; Jordan, Colin; Ilk, Dilhan; Blasingame, Thomas Alwin

doi:10.1016/j.jngse.2012.01.006

Cited by 45 publications

(15 citation statements)

References 46 publications

Supporting

Mentioning

Contrasting

Unclassified

Order By: Relevance

“…The final cylinder radius or rectangle length in horizontal direction determined from the match is assumed to be equal to the primary fracture half-length. Once the match is achieved, saturation and pressure-dependent outputs from the FR 6 analytical model are used in the calculation of pseudovariables and dimensionless variables used in turn for ratetransient analysis, as described by Clarkson et al (2012a) and Clarkson (2012a). The multi-phase version of ratetransient techniques such as type-curves and flowing material balance are used to confirm fracture permeability, and half-length.…”

Section: Transient Linearmentioning

confidence: 99%

Stochastic Modeling of Two-Phase Flowback of Multi-Fractured Horizontal Wells to Estimate Hydraulic Fracture Properties and Forecast Production

Williams-Kovacs

Clarkson

2013

All Days

View full text Add to dashboard Cite

Although high-frequency fluid production and flowing pressures (hourly or greater) are commonly gathered in multi-fractured horizontal wells (MFHW), this data has rarely been used by industry in a quantitative manner to characterize hydraulic fracture or reservoir parameters and there has been ongoing debate about the usefulness of this data. It is likely that the multi-phase flow nature and the possibility of early data being dominated by wellbore storage have deterred many analysts.This work will expand on the flowback analysis work presented by Clarkson (2012b). Consistent with that work, our interpretation is that the early flowback data corresponds to wellbore + fracture volume depletion (storage) and it is assumed that fracture storage volume is much greater than wellbore storage. From this flow-regime, bulk permeability (dominated by fracture permeability) and effective fracture half-length can be estimated. However, as pointed out by Clarkson (2012b) there is a large degree of uncertainty in this type of analysis as a result of the number of unknowns which are being adjusted to provide an adequate history match. To better understand the uncertainty and the impact of each parameter, stochastic simulation was used to provide a range of parameter values, which provide an adequate fit of the data, and to determine which parameters have the greatest impact on the match. Stochastic simulation is also used to derive a long-term forecast using parameters derived from flowback analysis. Additional improvements over previous work include the consideration of different fracture geometries, the use of the matchstick model to estimate fracture permeability and additional constraints on relative permeability curve selection. The field cases presented by Clarkson (2012b) for shale gas reservoirs are reanalyzed for proof of concept and demonstration of the developed techniques.

show abstract

Section: Transient Linearmentioning

confidence: 99%

Stochastic Modeling of Two-Phase Flowback of Multi-Fractured Horizontal Wells to Estimate Hydraulic Fracture Properties and Forecast Production

Williams-Kovacs

Clarkson

2013

All Days

View full text Add to dashboard Cite

show abstract

“…A zero sorption time was assumed (equilibrium desorption). Following the procedure of Clarkson et al (2012), an analytical simulator was first used to history match the numerically simulated data ( Fig. 4a and 4b), then the soft parameters used to achieve the match (i.e., absolute permeability and drainage area), along with output reservoir pressures, were used to generate the dimensionless variables for type-curve matching (Eqs.…”

Section: Example Applicationsmentioning

confidence: 99%

“…The dimensionless variables as defined previously also assume a static skin or hydraulic-fracture properties. Incorporation of changes in effective permeability to gas was discussed in Clarkson et al (2012). In order to incorporate skin changes into type-curve analysis, we start with the radial-flow (pseudosteadystate) equation for gas:…”

Section: Introductionmentioning

confidence: 99%

“…Because of the nonuniqueness of production analysis when the reservoir exhibits dynamic permeability or skin changes, we have chosen to link the output from analytical simulation [reservoir pressure, and s(t)] to the type-curve variables as described by Clarkson et al (2012) for the case of two-phase CBM reservoirs when k g is not static. This approach allows for consistency between analyses, but not necessarily uniqueness.…”

Section: Introductionmentioning

confidence: 99%

See 1 more Smart Citation

Production-Data and Pressure-Transient Analysis of Horseshoe Canyon Coalbed-Methane Wells, Part II: Accounting for Dynamic Skin

Clarkson

Behmanesh

Chorney³

2013

Journal of Canadian Petroleum Technology

View full text Add to dashboard Cite

In a previous study (Clarkson 2009), advanced production-analysis techniques, including production type curves and flowing material balance (FMB), were applied to Horseshoe Canyon (HSC) coal wells to establish the applicability of these techniques and to resolve the importance of multilayer behaviour for production analysis. The field examples chosen for analysis included single wells that exhibited production declines analogous to shallow gas wells, with decline in production occurring from day 1, and in one case exhibiting transient-flow characteristics. There are many more HSC wells that exhibit less-straightforward production characteristics, including flat or even inclining production. These wells have production profiles qualitatively similar to two-phase coalbed-methane (CBM) wells, yet lack water production. There are several possible explanations for the flat or inclining production behaviour, including changing skin associated with near-wellbore cleanup of drilling fluids over time, and increase in absolute permeability associated with matrix shrinkage. Regardless of the cause, these effects need to be accounted for in quantitative production analysis.In this follow-up paper, we continue to perform comparisons between multilayer and single-layer-equivalent production analysis of HSC wells, but focus on wells that exhibit inclining gas production. We develop a methodology to correct for changing skin in both type-curve and FMB analyses that allows this more-complex well behaviour to be analyzed. We validate the new methodology using a simulated example, and then apply it to actual field cases. Changing skin and absolute permeability by layer/coal zone was quantified through periodic shut-in/buildup testing of isolated coals throughout the life of the wells, and these dynamic properties were used in production-data analysis and analytical simulation. Comparing single-layer-equivalent and multilayer analysis, we have found differences in estimated-ultimate-recovery (EUR) values of less than 15% because the existence of one or two dominant (high-kh) coal zones. Additionally, we investigated the impact of free-gas storage on the results of productiondata analysis of HSC wells.The production-analysis methodology introduced in this work, while useful for analyzing HSC coal wells with dynamic skin/permeability, is expected to be applicable to a broader range of reservoir types that exhibit this complex behaviour. Production-Data-Analysis Techniques Incorporating Changing SkinThe adaptation of type-curve and FMB techniques for singlephase CBM reservoirs was previously discussed in Clarkson et al. (2007) and Clarkson (2009). The dimensionless rate and time

show abstract

“…Production data analysis is a powerful tool assisting researchers in attaining some significant reservoir properties as well as stimulation parameters. Recent advances in production data and rate transient analyses help researchers to obtain vital CBM reservoir properties such as permeability-thickness product (Kh), skin factor, initial gas and water in place, and time of peak gas production (Mohaghegh and Ertekin 1991; Aminian et al 2004; Clarkson et al 2012; Clarkson 2013; Karacan 2013; Salmachi and Yarmohammadtooski 2015). Production data analysis in CBM reservoirs can be complicated due to factors such as adsorption-driven gas storage mechanism, difficulties in determining relative permeability, and stress/desorption-dependent permeability (Clarkson et al 2007a).…”

Section: Introductionmentioning

confidence: 99%

Cross-formational flow of water into coalbed methane reservoirs: controls on relative permeability curve shape and production profile

Salmachi

Karacan

2017

Environ Earth Sci

View full text Add to dashboard Cite

Coalbed methane (CBM) wells tend to produce large volumes of water, especially when there is hydraulic connectivity between coalbed and nearby formations. Cross-formational flow between producing coal and adjacent formations can have significant production and environmental implications, affecting economic viability of production from these shallow reservoirs. Such flows can also affect how much gas can be removed from a coalbed prior to mining and thus can have implications for methane control in mining as well. The aim of this paper is to investigate the impact of water flow from an external source into coalbed on production performance and also on reservoir variables including cleat porosity and relative permeability curves derived from production data analysis. A reservoir model is constructed to investigate the production performance of a CBM well when cross-formational flow is present between the coalbed and the overlying formation. Results show that cleat porosity calculated by analysis of production data can be more than one order of magnitude higher than actual cleat porosity. Due to hydraulic connectivity, water saturation within coalbed does not considerably change for a period of time, and hence, the peak of gas production is delayed. Upon depletion of the overlying formation, water saturation in coalbed quickly decreases. Rapid decline of water saturation in the coalbed corresponds to a sharp increase in gas production. As an important consequence, when cross-flow is present, gas and water relative permeability curves, derived from simulated production data, have distinctive features compared to the initial relative permeability curves. In the case of cross-flow, signatures of relative permeability curves are concave downward and low gas permeability for a range of water saturation, followed by rapid increase afterward for water and gas, respectively. The results and analyses presented in this work can help to assess the impact of cross-formational flow on reservoir variables derived from production data analysis and can also contribute to identifying hydraulic connectivity between coalbed and adjacent formations.

show abstract

Rate-transient analysis of 2-phase (gas + water) CBM wells

Cited by 45 publications

References 46 publications

Stochastic Modeling of Two-Phase Flowback of Multi-Fractured Horizontal Wells to Estimate Hydraulic Fracture Properties and Forecast Production

Stochastic Modeling of Two-Phase Flowback of Multi-Fractured Horizontal Wells to Estimate Hydraulic Fracture Properties and Forecast Production

Production-Data and Pressure-Transient Analysis of Horseshoe Canyon Coalbed-Methane Wells, Part II: Accounting for Dynamic Skin

Cross-formational flow of water into coalbed methane reservoirs: controls on relative permeability curve shape and production profile

Contact Info

Product

Resources

About