Marcellus Shale Gas Asset Optimization Driven by Technology Integration

Kaufman, Peter; Atwood, Keith; Forrest, Gary; Walker, Kirby Jon; Wutherich, Kevin; Delozier, Denise; Perakis, Alex; Borchardt, Shannon; Hauser, Ken

doi:10.2118/164345-ms

Cited by 9 publications

(3 citation statements)

References 5 publications

(3 reference statements)

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“…This may point to rock quality (reservoir and completion quality) bearing a greater effect on production than stimulation parameters. Some publications on the Marcellus imply a correlation between production KPIs and rock quality across the Marcellus shale (Kaufman et al 2013;Zhou et al 2014). …”

Section: Marcellus Shale Production Analysismentioning

confidence: 99%

Shale Gas Production Decline Trend Comparison Over Time and Basins—Revisited

Baihly¹,

Malpani²,

Altman³

et al. 2015

Unconventional Resources Technology Conference

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Shale gas plays have taken precedence over shale oil plays since 2009. With the price of oil falling, gas may take a more predominant role in Ford. Much has changed over this time, and rig counts have fallen in gas-rich areas all over the US from their 2010 numbers. Over that same period, gas production from these five plays has increased from 9.2 Bscf/D to 16.7 Bscf/D. Shale gas decline trends continue to be a point of contention in the industry from some consultants and investment firms. This manuscript builds upon the previously published work to include new production from the last five years. Updates to the estimated ultimate recovery (EUR) analyses and the overall economic feasibility of horizontal shale gas wells were made taking into consideration of how new wells have performed.In this new study, we updated the production of existing wells (used in our previous study) and included production from new wells. We used the same geologic areas as before, with a refinement made for the Haynesville and Eagle Ford plays. We compared the original Arps decline curve estimation predicted in the previous publication and the new estimation performed with five years' additional data. Changes in EUR by play and vintage were also studied as was the impact of available production history on Arps's decline parameters for each basin. From these analyses, we developed recommendations for a minimum production period to properly assess EURs when using Arps method.The production type curves by play were updated with wells drilled in the studied geographic areas from 2010 onwards. These newer vintage wells were compared with older wells to determine which plays are still realizing improved well performance and which plays have seen some plateauing or decrease in production. The drilling and completion factors were analyzed in plays where average well production continues to improve, and we investigated possible contributing factors impairing production of new wells in plateauing shale plays.An economic analysis was performed to determine the break-even cost for each shale gas basins studied. The decline curves and EURs were incorporated along with well costs. This study helps to explain if wells are still improving in each basin, what the improvement drivers are, and what impact infill drilling has had on these plays.

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Section: Marcellus Shale Production Analysismentioning

confidence: 99%

Shale Gas Production Decline Trend Comparison Over Time and Basins—Revisited

Baihly¹,

Malpani²,

Altman³

et al. 2015

Unconventional Resources Technology Conference

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“…In a study of wells drilled in the Marcellus Shale in Pennsylvania, the compressional and shear sonic logs were found to exhibit workable correlations with normalized production data over a 60-day period (Kaufman et al 2013) (Fig. 8).…”

Section: Field Examplementioning

confidence: 99%

The Use of Net Pay Concepts in the Exploitation of Shale-Gas Deposits

Majid¹,

Worthington²

2013

All Days

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The role of net pay in unconventional reservoirs continues to evolve as a design criterion for reservoir stimulation and well completions. Unlike conventional reservoirs, shale-gas development is not yet at the stage where longstanding net pay protocols have been tried and tested. Therefore, any protocol has to be regarded as being at a pilot stage, especially in view of the pronounced complexity of shale-gas systems. This state of affairs is progressed by adopting a set of net pay criteria and transposing this into a generic petrophysical workflow that interfaces with other key disciplines such as geochemistry and geomechanics. Essential parameters are total organic carbon (in the setting of thermal maturity), fracturability (based on sand volume fraction and thence brittleness), natural fracture density, effective gas permeability, and total porosity as an input to gas in place. The deliverables in the form of target net pay intervals are based on functional cut-offs for each given reservoir system and for different appraisal fronts within the same reservoir system. This is important because different methods of reservoir zonation can result in very different zonal characteristics and associated parametric relationships. The estimation of uncertainty in cut-off specifications and its impact on the resulting net pay intervals has been approached with reference to a commensurate suite of characterizing well logs groundtruthed by core analysis in at least one key well. These considerations lead to specific ranges of cut-offs for immediate application. Thus, the identification of net pay and thence candidate intervals for completion is placed on a quantitative footing. This is an important contribution to development planning in these highly complex unconventional systems.

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“…Horizontal drilling technology is largely utilized in unconventional shale gas plays (namely: Barnett, Fayetteville, Haynesville, and Marcellus) development. When this technology is coupled with multi-stage hydraulic fracturing, it can reach trapped hydrocarbons in very low permeability shales (Kaufman et al, 2013). Basically, horizontal wells are applicable in fractured reservoirs, thin and low permeability formations, and heavy oil reservoirs (Belvalkar and Oyewole, 2010).…”

Section: List Of Figuresmentioning

confidence: 99%

Hydraulics and Well Control Complications in Unconventional Shale Laterals

Elshehabi¹

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Unconventional shale resources are drilled horizontally following the geologic bed dip upward or downward to maximize reservoir contact. Despite the efforts to control formation pressures, well control emergencies arise. Wellbore communication with high pressure zones through natural or induced fractures is a major cause of blowouts in unconventional shales. The philosophy of well control is to maintain the bottomhole pressure while balancing the formation pressure; however, it is a challenging process. The objective of this study is to investigate mud hydraulics and well control complications in unconventional shale laterals. This included the impact of wellbore configuration (inclined upward or downward laterals), drilling fluid type (water or oil based mud), and drillstring configuration (drillpipe, casing, or liner). This research employed an interactive drilling and well control full-scale simulator for more than 500 hours of real-time operations. It also utilized a robust steady-state hydraulics and multiphase dynamic well control program. A hydraulics base model was developed and verified with field data from a recently drilled Marcellus Shale well in Monongalia County, WV. In inclined upward laterals, gas bubbles migrated and accumulated at the lateral end. Consequently, the choke experienced lower pressure, volume, and gas discharge rate for extended periods of time. Thus, higher circulation rates and longer operation times were essential to flush-out the dispersed and trapped gas bubbles. The deeper and over-pressurized Utica Shale presents more challenges compared to Marcellus Shale wells. Well integrity was verified by monitoring surface choke, casing shoe, and bottomhole pressures throughout the entire well control operations. This research revealed that it is crucial to identify accurate hydraulics and well control complications for unconventional shale laterals. Some examples were drilling inclined upward and downward laterals using different string and fluid configurations. This improves rig and personnel safety and diminishes the environmental risks and hazards associated with blowouts.

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Marcellus Shale Gas Asset Optimization Driven by Technology Integration

Cited by 9 publications

References 5 publications

Shale Gas Production Decline Trend Comparison Over Time and Basins—Revisited

Shale Gas Production Decline Trend Comparison Over Time and Basins—Revisited

The Use of Net Pay Concepts in the Exploitation of Shale-Gas Deposits

Hydraulics and Well Control Complications in Unconventional Shale Laterals

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