The U.S. shale revolution has matured and is witnessing a new development: Restimulation (refracturing) of horizonal wells in production decline. This is a hot and emerging field of research. Let’s take a look.
Rasoul Sorkhabi
Editor, Core Elements
Reservoir Pressure Depletion and Stress Changes
Shale Gas Extraction Through Hydraulic Fracturing/ European Environment Agency
A new study simulates certain factors controlling subsurface stress changes in shale gas reservoirs after long-term production.
Context: Past studies have shown that in-situ stresses in shale reservoirs undergo significant changes in orientation, and even reversals, due to pre-existing natural fractures and faults, shale bedding, and long-term oil and gas production.
New study design:
The new study is a 40-year simulation of coupled geomechanical and fluid flow parameters based on Biot’s theory of poroelasticity, discrete fracture model, and finite volume model.
Model input parameters include dimensions of the domain, initial stresses along x, y, and z axes, Biot coefficient (0.8), Poisson’s ratio (0.15), rock elastic module (24 gigapascal), matrix permeability (500 millidarcy), and matrix compressibility coefficient.
Major findings:
Extreme changes in stresses along x, y, and z directions occur at different positions and different times, controlled by pore pressure gradient. The greater the pressure gradient between the fracture and rock matrix, the greater the stress change.
Different microscopic seepage mechanisms of shale gas (adsorption, desorption, diffusion, and slippage) influence the storage and transmission of shale gas, thus leading to varying distribution of reservoir pressure and stress.
When theinitial stress difference in shale formation is larger, it becomes more difficult for stress reversal to occur. The stress reversal may not ever occur if the initial stress difference exceeds a certain limit.
The number of natural fractures and the approaching angle (fracture to horizonal axis) of natural fractures control the stress evolution in shale formations.
As the number of natural fractures increases, the orientation of maximum horizontal axis slightly increases.
As the approaching angle increases, stress reversal area becomes smaller.
Why it matters: Subsurface stress changes associated with reservoir pressure depletion have important impacts on the performance of infill wells and restimulation of shale formations.
Go deeper: Read the full article by Wang and colleagues in Petroleum.
A message from AAPG Academy and AspenTech
Register now to join AAPG Academy and AspenTech on 12 December at 9am CST to learn more about how 3D reservoir models, when combined with reservoir engineering solutions, can increase your understanding of reservoir flow performance.
AspenTech Reservoir Modeling Expert Sasan Ghanbari will share how to:
Construct a robust structural uncertainty model, combining various data types and their uncertainties
Integrate the model into workflows for history matching and production forecasting
Quantify the impact of horizon and fault uncertainty on production and assess risks
A different group of scientists have reported on restimulation of shale gas wells in China’s largest shale gas production field, comparing fracturing efficiency and water consumption across two refracturing methods.
The Fuling Field:
The Fuling Shale Gas Field has an estimated 900 billion cubic meters of natural gas—34 percent of China’s proven shale gas reserves.
The main producing formation is the Wufeng Shale of Late Ordovician-Lower Silurian age.
The field has more than 800 wells with a daily production of more than 20 million cubic meters.
Methodology: The researchers compared two refracturing methods:
Temporary plugging and diverting refracturing (TPD)
Comparison: Researchers then compared the results of refracturing two wells by TPD with two other wells by WR.
Fracturing efficiency of WR was superior compared to TPD. This was evident from the higher completion rate of proppant injection, which indicates whether the fracture will remain open for a long time.
However, water consumption when using WR was significantly higher than when using TPD. The water consumption by WR was also higher than that of the initial fracturing.
What’s next:
Three hundred and fourteen wells developed in the Fuling Shale Gas Field from 2013–2017 require refracturing in the coming years.
While these refracturing projects will provide new data and gas production, they will also consume about 14 million cubic meters of water.
The researchers forecast that water consumption for the Fuling Shale Gas Field over the next decade will be 76 million cubic meters of water.
Why it matters:
According to the International Energy Agency, water consumption for shale gas production per unit of volume is 200 times higher than for conventional natural gas production.
In the United States, shale gas production requires an average of 15,000 cubic meters of water per well for hydraulic fracturing. In China, this number easily doubles.
Last week’s quiz question was: What is the largest conventional oil field in the world in terms of reserves and production? Where is it located? What are the producing reservoirs?
Thank you to all who responded.
Here is a full answer: The largest conventional oil field in the world is Ghawar in Saudi Arabia. Discovered in 1948, Ghawar produces a maximum of 5.2 million barrels of oil per day and, more recently, 3.8 million barrels of oil per day. Producing reservoirs are the Jurassic Arab-D limestone for oil and Paleozoic formations for natural gas. Total recoverable oil reserves have been estimated variously from 46 to 140 billion barrels.
As a follow up, this week’s question is: What are the second and third largest conventional oil fields in the world?
Please send your response by December 12 to editorial@aapg.org (subject line: Core Elements Quiz).
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