Monitoring - Injectivity/Falloff

Unit Mobility Case: If the properties of the injected fluid are identical to the properties of the fluid in the reservoir, the resulting piston-like displacement has no discontinuity in the flow properties across the flood front. The governing equations reduce to the single phase, homogeneous fluid case. This is often not the case in PWRI.
Buckley Leverett Displacement concepts are more commonly used for a range of mobility ratios and for identifying a transition zone, a flushed zone and an uninvaded zone. Three generic zones include a water bank (or invaded zone) adjacent to the injection well, a transition (or invaded zone) where the oil saturation varies from S_or to an initial value, S_oi and an uninvaded zone where the water saturation is at its initial value, S_wi.

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If the mobility ratio is less than or equal to 1, the displacement will be stable and piston-like. There will be a short transition zone, and in terms of recovering oil, the displacement efficiency will be relatively high.
If the mobility ratio is greater than 1, the displacement can be unstable with water channeling, fingering and bypassed oil. There is a large transition region and high recoveries require extended production to very high WOR.

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In an injectivity test, the well is shut-in until the pressure is stabilized and then injection is begun at a constant rate while recording the bottomhole pressure.
- If the injected fluid has exactly the same properties (density, viscosity, compressibility, and wetting characteristics) as the reservoir fluids, an injectivity test would be identical to a pressure drawdown test except that the constant rate, q, would be negative.
- If only the density differs from that of the reservoir fluid and the reservoir is homogeneous, the injection profile would be uneven. The injected fluid will sink or ride over the reservoir fluid and the net pay, h, which should be used in the interpretation, would not be the same as the net pay.
- If the viscosity and/or the compressibility and/or the wetting characteristics are different from those of the reservoir fluids, an interface or front will form in the reservoir between the injected and the reservoir fluids and the permeability will depend on the saturation - relative permeability is important.
A pressure falloff test is usually preceded by a long injectivity test. Injection is then stopped while recording pressure. Therefore, a pressure falloff test is similar to a pressure buildup test, but only if the properties of the injected and reservoir fluids are the same.
In some falloff tests, the pressure at the wellhead goes on vacuum. When this happens, the level in the tubing drops and the wellbore storage coefficient changes. To avoid this situation, bottomhole shut-off is required or it is necessary to run a two-rate falloff test.
In a two-rate falloff test, the injection rate is changed from q₁ to q₂ while recording pressure.
If the injected fluid is the same as the reservoir fluid, conventional production well multi-rate falloff analysis can be used. Alternatively, if the injected fluid is not the same as the reservoir fluid but the injected fluid has already filled a substantial region around the well, a falloff or two-rate falloff, preceded by a short injectivity test can be equivalently interpreted - the position of the front cannot be determined.

Wellbore storage effects can be significant during some injection tests. The wellbore storage is estimated from a log-log plot of pressure difference versus early time. The wellbore storage effects will die out 1.5 cycles after the start of deviation from straight line.
Wellbore storage may not be constant for a falloff test in a well injecting on vacuum.
For a fractured injection situation, or a case where there is a stagnant (non-propagating) fracture, you can use storage to your advantage. Volume indicated by storage above that expected for the wellbore itself can provide indications of the volume of the fracture/fracture system.
As a fracture closes, the overall storage will change. Koning has used this effectively for inferring fracture dimensions.

Conventional falloff tests from layered reservoirs usually suffer from crossflow between layers, particularly if the layers communicate only through the wellbore and/or permeability contrast between layers is high.
The crossflow problem becomes more severe if the pressure and/or the drainage radius of each zone are/is different. The wellbore crossflow may continue during the entire period of the test. A false straight line on a semilog plot may even be observed. In many instances, the pressured data alone may not reveal any information about the wellbore or formation crossflow.
Even if crossflow is not a complicating factor, conventional tests may reveal only the behavior of the total system. Furthermore, the behavior of a multilayer formation may not be distinguished from the behavior of a single-layer formation even though a multilayer reservoir may have distinct behavior without wellbore storage effects.
Be careful with your test design and interpretation. Refer to the Best Practices outlined under Layered Formations.

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This usually requires adopting of an analysis model that incorporates some principles representing the fracture. You should definitely refer to Larsen, L. and Bratvold, R.B.: "Effects of Propagating Fractures on Pressure-Transient Injection and Falloff Data," SPE 20580, paper presented at 65th Annual Tech. Conf. Exhib., New Orleans, LA (Sept 23-26, 1990).
Larsen and Bratvold modified the work of Bratvold and Horne (for radial flow) to cover flow in elliptic systems and extended this to account for the propagating fracture. The model includes convective heat transfer as well as effects of relative permeabilies. Solutions to both the injection and falloff problems are derived using the quasi-stationary method.
The concepts are similar to Koning and Niko, and Koning except that more general multizone elliptic models are allowed and the the pressure transient behavior under various propagation models are considered in more detail. You should also review the work of Koning and Niko and work by a number of authors at Shell.

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This project is continuing and the focus in Phase 2 is improvement of methods for evaluating falloff testing.
Sponsoring organizations identified significant weaknesses in falloff and other pressure transient methods applied to injection wells. They chartered evaluation/development of improved pressure transient techniques for Phase 2.
This is ongoing.