Comparison of Multiphase-Flow Results in Transverse vs. Longitudinal Fracturing
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There is an ongoing debate about whether the best practice is to drill a horizontal well in the direction of minimum horizontal stress, which would create a transversely fractured well, or to drill the well in the direction of maximum horizontal stress, which would create a longitudinally fractured well. This paper presents the results of a comprehensive multiphase-flow study that investigated the relationship between the principal stresses and lateral direction in hydraulically fractured horizontal wells.
Rock mechanics research has shown that hydraulic fractures propagate perpendicular to the minimum horizontal stress in a normal fault environment, creating transverse fractures. This occurs if the perforations are aligned with the preferred fracture plane, which, in this case, is the maximum horizontal stress. However, the debate has centered on whether transversely fractured horizontal wells or longitudinally fractured horizontal wells are appropriate and best practice in a given area and for a given reservoir permeability.
The motivation for conducting this research came out of the realization that all previous studies that looked into the performance comparison of transversely vs. longitudinally fractured horizontal wells were limited in scope either by the range of reservoir permeability studied or by the single-phase-flow models that were used. None of the previous work undertook extensive integrated completion and reservoir simulations that modeled multiphase flow in transversely fractured vs. longitudinally fractured horizontal wells. This study incorporated the effect of non-Darcy flow, adsorption gas, the relative permeability effect on fluid flow in the fracture, and the effect of stress-dependent permeability on fracture conductivity, which were missing in previous studies.
Multiphase-flow study and performance comparison of transversely fractured horizontal wells vs. longitudinally fractured horizontal wells in tight sands and unconventional reservoirs with stress-dependent permeability were conducted using three different reservoir-simulation models. The first reservoir-simulation model was for a dry-gas reservoir (in contact with water) and produced only gas and water. The second reservoir-simulation model was built for a black-oil-type reservoir (undersaturated), which honored accurate reservoir-fluid properties for Permian Basin oil. The third reservoir-simulation model was built for saturated reservoirs and used compositional reservoir-simulation methods and honored the reservoir-fluid properties of Eagle Ford oil.
For each of the three reservoir-fluid types—dry gas, black oil, and compositional oil—72 static reservoir-simulation models were built to study the effect on well performance of well azimuth, reservoir permeability, and the number of fractures. This study investigated the effect of stress-dependent permeability on induced fractures, the effect of permeability changes in the fracture from the wellbore to the tip of the fracture, and the effect of adsorbed gas on well productivity, estimated ultimate recovery (EUR), and reserves.
Principal Stresses and Fracture Orientation
In a normal fault-stress environment, the vertical stress is the primary principal stress, the maximum horizontal stress is the secondary principal stress, and the minimum horizontal stress is least principal stress. Fig. 1 shows a horizontal well with 10 transverse fractures, which was drilled in the direction of the minimum horizontal stress. Fig. 2 shows a horizontal well with four longitudinal fractures that was drilled in the direction of the maximum horizontal stress.
While this study compares the performance of transversely fractured vs. longitudinally fractured horizontal wells, there is a well-documented uncertainty in the direction and azimuth of the longitudinal fracture configuration once it exits the perforations. The direction of propagation is dictated by the intermediate- and far-field in-situ stresses. An earlier study showed that deviation of more than 10° from the azimuth of the preferred fracture plane would always create transverse fractures as the fracture propagates away from the wellbore.
Results and Discussion
Dry-Gas Reservoir (Two-Phase: Gas and Water). The result from the dry-gas reservoir modeling was a two-phase (gas/water) simulation. Analysis reveals three interesting findings. First, comparison of the gas recovery from the single-phase simulator vs. the result of a horizontal well with 40 transverse fractures from this study were exactly the same. Second, at permeabilities higher than 1.0 md, all the transversely fractured and longitudinally fractured horizontal wells had similar well performance. The number of stages/fractures and well orientation or azimuth did not make a difference in terms of well productivity or recovery. Third, at lower permeability, longitudinally fractured horizontal wells performed worst among all the wells studied. This means longitudinally fractured wells are not suitable for low- and ultralow-permeability unconventional resources.
Black-Oil-Type Reservoir (Three-Phase: Oil, Gas, and Water). The reservoir fluid used in the black-oil model was Permian Basin oil. There were two reasons for a black-oil reservoir simulation to be selected and for Permian Basin oil to be used. First, the Permian Basin oil’s saturation pressure was 2,000 psi while initial reservoir pressure used in the study was 4,000 psi. Hence, at reservoir conditions, there was no free gas and only two fluid phases existed—oil and water—which a black-oil reservoir simulator can model fairly without significant errors. Second, test models were run to compare the results of a black-oil model with those of a compositional model using Permian Basin oil, and the result showed that there was very little difference in recovery (of oil and gas).
The cumulative-production results from the black-oil reservoir simulator compare oil recovery for transversely fractured horizontal wells with those of longitudinally fractured horizontal wells across a permeability range from 10 nd to 10 md. There were seven transversely fractured horizontal well cases and two longitudinally fractured horizontal well cases. The results show that, at low reservoir permeabilities, longitudinally fractured horizontal wells performed poorer among all cases studied. In fact, a transversely fractured horizontal well with only four fractures in a 4,000-ft lateral length performed better than a longitudinally fractured horizontal well with four fractures. However, at higher reservoir permeabilities, longitudinal fractures outperformed transverse fractures. The result shows that a longitudinally fractured horizontal well with only two fractures had a higher cumulative oil production than a transversely fractured horizontal well with 40 fractures at reservoir permeability of 2.0 md. Therefore, at higher permeabilities, the optimal well-completion method is to drill longitudinally fractured horizontal wells.
Compositional Reservoir (Three-Phase: Oil, Gas, and Water). The compositional reservoir-simulation models had reservoir-fluid properties from Eagle Ford oil. The study used a compositional reservoir simulator because the reservoir was saturated (below bubblepoint pressure) and all three phases (oil, gas, and water) existed at in-situ reservoir conditions. In the study, the reservoir pressure was 4,000 psi at a reference depth of 8,000 ft. The study investigated the effect of reservoir-oil composition on the performance of transversely fractured vs. longitudinally fractured horizontal wells in tight sands and unconventional reservoirs with stress-dependent permeability.
Comparison of oil recovery vs. reservoir permeability for transversely fractured vs. longitudinally fractured horizontal wells using Eagle Ford oil in a compositional reservoir simulator shows three significant findings. First, less oil but more gas was recovered (using the Eagle Ford oil) compared with the black-oil reservoir simulator, which used Permian-oil fluid properties. In fact, only 3 million bbl of oil was recovered in the Eagle Ford oil compositional modeling compared with the 17 million bbl of cumulative oil in the Permian Basin oil case. Second, longitudinally fractured horizontal wells outperformed transversely fractured horizontal wells at moderate and high permeability ranges. Third, the reservoir-fluid composition affected the critical permeability.
Stress-Dependent Permeability. The effect of stress-dependent permeability on well economics, productivity, and reserves was investigated for the three reservoir-fluid types studied using two methods—porosity and permeability multipliers and a total-compressibility equation. Stress-dependent permeability had no effect on gas EUR in the dry-gas reservoir. The results from both equations showed no effect on dry-gas reservoirs. Similarly, there was no stress-dependent-permeability effect in the condensate reservoir, which used Eagle Ford oil.
The black-oil simulations, which used Permian Basin oil properties, showed a noticeable effect on oil recovery from stress-dependent-permeability effects on induced fractures. There was -1.20% change in both oil recovery and discounted recovery when stress-dependent permeability was incorporated into the models vs. the model without it. One important finding is that the effect of stress-dependent permeability occurred later in the life of the wells. A second finding is that reservoir-fluid type (gas, condensate, or black oil), rock mechanics, and reservoir depth can influence the effect of stress-dependent permeability on well recovery.
Comparison of Multiphase-Flow Results in Transverse vs. Longitudinal Fracturing
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