Method	Application	Precautions
Injectivity/ Falloff (including multi-rate)	Permeability, skin, front position, boundaries, average reservoir pressure	Non-unit mobility Non-isothermal Relative permeability differences Density differences
Falloff for Average Reservoir Pressure	Average reservoir pressure	Simple solutions apply to unit mobility situations Consider the shape of the injection area and the influence of other injectors and producers The extrapolated pressure can be significantly different than the average pressure. This is very important. Extreme complications in layered formations, especially if zones are not individually isolated. Significant difficulties in interpreting data for fractured injectors.
Hall Plots	Progressive damage, stimulation, assessment of skin	Essential to use bottomhole pressure Averaging modulates influence of events and only progressive deterioration is often readily evident.
Pulse Testing	Permeability, permeability anisotropy, storage, compressibility or average reservoir pressure and reservoir continuity.	Signals are small and measurements can be affected by noise. There is no way in practice to account for wellbore storage without assuming that the reservoir is homogeneous and isotropic. At least two wells are required.
Interference Testing	As above	Long duration test. Additional considerations are required if boundaries are close. The rates at the active wells should be fairly constant. Wellbore storage and skin effects at the pulser and the responder (active and passive wells) can lead to complexities and uncertainties in the results, especially if the dimensionless distance between the two wells is less than 1,000 or if the duration of the pulse is too short. There are other complicating factors for pulse testing (lunar-solar tides, oilfield activities, natural or hydraulic fractures, multi-layering, the presence of gas ….Lunar and ocean tides are periodic. In an inland reservoir, these can cause pressure variations of ±0.015 psi. In near-shore and offshore reservoirs, the pressure fluctuations due to tides can be ±1 psi. The high compressibility of gas tends to suppress or attenuate the pressure signal at the observation well. Unless, and even if, the reservoir is homogeneous, isotropic and infinite, interpretation can be ambiguous and conjectural. At least two wells are required.
Step Rate Testing	Step rate testing allows for determining when a fracture will propagate and when a preexisting fracture will reopen. It can be run after a conventional falloff or a final falloff segment can be used in the test. Repeated falloff testing can also be used to assess if a reservoir has been altered by thermal changes in in-situ stresses or changes in kh associated with thermal effects.	Varying fluid loss. Out-of-zone growth. Varying perforation/completion friction needs to be reliably accounted for. Damaged cement bond can make step down cycles difficult to interpret. Fracture reopening may cause interpretation difficulties. Consider transient effects. Consider thermo- and poroelastic stress changes.
Hydraulic Impedance Testing	Detect hydraulic (or natural) fractures intersecting a wellbore, determine the fracture closure pressure (indicative of the total minimum in-situ stress), and, to estimate fracture dimensions.	Are frictional effects in the tubulars adequately handled? Coupled with two dimensional fracturing model? May be susceptible to changes in fracture compliance due to cake. Some doubt about selection of the average fracture width? Some concern about the effects of near-wellbore tortuosity and height? Some anecdotal inferences as to insensitivity to fracture height? Some possibility for interpretive confusion due to out-of-gauge but unfractured wellbores? Bias towards uppermost fractures or washouts? Anecdotal references to excessive attenuation if the fracture is too long?
Production Logging Testing (PLT)	Run to assess conformance issues and partitioning of flow into individual lithologic zones or into discrete portions of long sections (i.e., preferential injection into the heel in some horizontal wells).	As intervention is required, costs can be prohibitively high, unless scheduling corresponds to planned workover activities. Even so, operations can be quite expensive. Interpretation of pressure transient information in multiple zones taking fluid requires rigorous methods and analysis. Interpret temperature data with caution as cooldown/warmup may be an artifact of injection into another area. Strongly consider fibre optics methodologies for future wells.
Tracer Surveys	Tracers are added to the injection fluid and collected by sampling at production wells (single well tracer tests can also be carried out). Directional flow trends Flow barriers Communication between zones Sweep efficiency	Safety and regulatory compliance Selecting an acceptable tracer Uniqueness of interpretations For detailed, quantitative interpretation, sophisticated modeling may be needed Consider the cost of the additional services and compare it with the benefits.
Fibre Optics	Fiber optics involves the transmission of light through fibers or thin rods of glass or some other transparent material with a high refractive index. Light that enters one end of a fiber can travel through the fiber with very low loss, even if the fiber is curved. Images can be transmitted, as can data. Continuous or point measurements of some in-situ parameters Communications Temperature, pressure, rate, sand concentration, vibrations ...	While it is a relatively immature technology, future applications seem promising for continuous monitoring and minimizing the number of interventions (both for remedial work and for measurements). Vendors have been working to overcome certain issues Hydrogen attenuation (coatings, etc., usually overcome this, but; long-term field performance will be the final reflection of this). Avoiding water ingress is necessary but generally doable with new wet-connect systems and hermetic sealing. Durability? Cost: You decide. There will be extra costs for materials, for installation and for continuous monitoring. Assess these against future operational expenses for intervention (remedial or testing).
Leakoff Testing	Formation Integrity Testing (FIT) is performed to evaluate the integrity of the casing shoe. Conventional leakoff testing provides rudimentary approximations of the pressure at which a formation will breakdown.	For FIT, little information on the formation can be recovered. If the shoe does not fail, only an approximation of the minimum level of the breakdown pressure is possible. Conventional leakoff testing can provide an indication of the breakdown pressure of the formation - this is not the minimum in-situ stress. Conventional leakoff testing commonly provides characteristics of non-pay, unless you drill far enough ahead before the measurement.
Extended Leakoff Testing (XLOT)	An extension of conventional leakoff testing where there is more "rigorous" recording (nominally) of pressure and rate data, where there are usually somewhat extended shut-in periods following injection, and where multiple injection/shut-in cycles are performed. The minimum and in some cases, the maximum horizontal stress can be determined.	Slight additional expenditure in comparison to conventional leakoff testing. Data interpretation is quite possible but it may not be a rudimentary operation (may require assistance from a "specialist." Information may be biased to non-pay. This is not necessarily completely "bad" because it is desirable to know the stress conditions in bounding zones. Be patient and record adequate data while the well is shut-in. Run multiple cycles. Preferably record data electronically. Adequately correct data to bottomhole conditions presuming there is no downhole measurement. Rates are usually low enough that frictional losses may be second order.
Microhydraulic Fracturing	Fundamentally similar to XLOT. Stress measured by hydraulic fracturing in any zone that you can isolate.	Expense and methods for isolating zones. Data interpretation is quite possible but it may not be a rudimentary operation (may require assistance from a "specialist." Be patient and record adequate data while the well is shut-in. Run multiple cycles. Preferably record data electronically. Adequately correct data to bottomhole conditions presuming there is no downhole measurement. Rates are usually low enough that frictional losses may be second order.
Tiltmeter Testing	Fracture orientation/dimensions	Uniqueness of inverted signals. Some depth limitations if in-well devices not used. Impact of noise on in-well devices? Cannot be run in steeply inclined or horizontal wells.
Microseismic Monitoring	Orientations of one or more fractures and some indications of the areal dimensions	Uniqueness of inverted signals. Complex interpretation. Sophisticated noise filtering and background monitoring are required.
Real-Time Diagnostics	Using technology borrowed from the stimulation community, some indications of depth of damage can be determined during acidizing operations and Nolte-Smith analysis concepts can be implied to infer fracture growth characteristics.	Extensions of the analyses to three-dimensional geometries needs to be considered with caution. The fluid loss mechanisms in most of the hydraulic fracturing interpretations are usually based on the square root of time.

Method	Continuous	"Point-in-Time"
Injectivity/Falloff		X
Hall Plot	X
Pulse Test	x1	X
Interference Test	x1	X
Step Rate Test		X
Hydraulic Impedance Test		X
Production Logging Test	x2	X
Tracers	x3	X
Fibre Optics	X4	X4
Leakoff Test		X5
Extended Leakoff Test		X
Micro/Minifrac		X
Tiltmeter	X6	X7
Microseismic	X8	X9
Real-Time Diagnostics	X	X

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1	Would need dedicated observation well(s).
2	With continuous downhole measurement over zone(s). There could be a lot of noise.
3	Possible, but may be expensive.
4	Can monitor temperature, rate, pressure, vibration continuously for use in other continuous processing techniques. Can be used for recording environmental parameters (temperature, pressure, rate) for controlled "point-in-time" measurements.
5	During construction.
6	Likely need dedicated observation well(s). There are current limitations on angle of deployment of tools.
7	Need an "abnormal" event to sense changes over a short time period (frac job?).
8	Need dedicated observation well(s) or possibly in the future sea bed sensors.
7	Need an "abnormal" event to sense changes over a short time period (frac job?).

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Method	Stresses?	Comments
Injectivity/Falloff	Yes	Some of the early work in interpreting pressure signatures after a shut-in started to conceive of looking for anomalies in the pressure signature by using standard pressure transient analysis time transformations - i.e., looking for trends in the declining pressure as functions of Horner time, the square root of time and the quarter root of time. These concepts still apply. You are looking for pressures where there is an indication that a fracture has closed and there is a change in flow regimes. This is commonly complicated because no fracture will completely close and there will be some sort of linear feature at all times. Regardless, look for "anomalies" or changes in flow regime with time, using standard time transformations. Logarithmic diagnostic curves are often useful and superposition techniques may assist in accounting for the rate fluctuations in the actual injection portion of the test.
Hall Plot	Possibly	If a fracture has been created, the Hall plot may ultimately show a reduction in slope, reflecting the associated decreased skin. It can be possible to extrapolate backwards on the plot (over the section of reduced slope) and back the pressure out where the change occurred from the pressure function. This bottomhole pressure should approximate the pressure required for equilibrium between the pressure in the fracture and the in-situ stresses acting to close it. This analysis is complicated by the fact that the Hall plot can represent substantial injected volumes and the in-situ stress may be changing because of poroelastic and thermoelastic effects - i.e., be careful in how you extrapolate. In fact, this may be advantageous. Any difference between the extrapolated pressure and the actual bottomhole pressure when the change is inferred to occur can be indicative of changes in stress due to any changes in local/regional temperature and pressure. As always, any Hall plot analysis is contingent on reliable bottomhole pressures and knowledge of the formation pressure variation with time.
Pulse Test	Unlikely
Interference Test	Maybe	If there are incidents at an injector, they may be reflected by measured changes at a producer and at one or more of the observation wells when fracturing changes the time to breakthrough or increases the sweep.
Step Rate Test	Yes	One of the fundamental uses of step rate tests (both step-up and step-down) is to determine the so-called parting pressure which is going to be representative of the current total in-situ stress acting normal to the fracture, to prevent it from opening. Don't forget that fractures do not completely close when you shut down and you probably want to adopt non-routine methods of step rate analysis (incorporating superposition techniques) to evaluate your data. For more information, click on the link to the left.
Hydraulic Impedance Test	Yes	Consider an actual example, for a new North Sea well. An SRT was done to start up. Before fracing, in a 4 1/2 into 7-inch liner, when HIT was done, reflection was seen from the liner and the bottom of the well. Above frac pressure, you could see the frac and the tubing. When the pressure was reduced, you saw the initial signature. This was a new well and you could see that, in fact, it has been fraced. Consider another example. This was for an older North Sea well. Falloff data were available. The response for multiple HITs during falloff can be summarized as: "AS YOU GO DOWN IN PRESSURE DURING A PRESSURE FALLOFF, EXPECT TO SEE CHANGE IN SIGNAL. IMPEDANCE CONTRAST IS CHANGING AND THE FRACTURE IS CLOSING. AMPLITUDE ALSO CHANGES." With fracture closure, reflection coefficients will change, according to the degree of closure. BP has had good success in inferring the minimum in-situ stress by processing the variation between the reflection coefficient and the bottomhole pressure. The procedure is to take the reflection coefficients and plot them as a function of bottomhole pressure (refer to Figure 1). If you assume a linear elastic fracture system and self-similar closure, you can relate the reflection coefficient to a pressure that is characteristic of what is going on in the fracture. Extrapolate the reflection coefficient to zero and use that pressure as a measure of the in-situ stress. If you use linear elastic and self-similar closure assumptions, it is possible to do this extrapolation with only two points on the plot - you are implicitly coupling a fracture model with the pressure measurements. This overcomes the commonly encountered difficulty that fractures may not completely close and as such, in-situ stress cannot be precisely defined. Figure 1. Reflection Coefficient versus pressure. Complimentary SRT data supports the use of this type of plot for inferring in-situ stresses.
Production Logging Test	Possibly	If surveys at done at various surface injection rates, as is commonly done for testing in layered formations, it may be possible to discriminate the pressure at which fractures practically close (as indicated, they may never close completely).
Tracers	Possibly	If tracers are recovered at a producer and the concentration changes due to an event at the injector, some inferences on the pressure required to open/close a fracture(s) [and hence the stress regime] may be possible.
Fibre Optics	Yes	As pressure, rate and temperature can be potentially measured continuously in time, along the length of a target section, local changes in injectivity can be correlated with fracture opening/closure and hence, with the in-situ stress regime.
Leakoff Test	Marginal or No
Extended Leakoff Test	Yes	The premise of an extended leakoff test is to allow the in-situ stress regime to be inferred. It may be possible to determine the minimum and the maximum in-situ stresses.
Micro/Minifrac	Yes	This is the specific purpose of this type of measurement. As an aside, there continues to be a movement to determine in-situ stresses from logging information. With adequate calibration of the logs, often using this type of stress measurement, this is a reasonable approach. In cased/perforated hole, the minimum stress can be inferred. It may be possible to infer the maximum principal stress if the measurements can be safely and economically done in open hole.
Tiltmeter	Possible	Depending on the quality of the data recovered, it may be possible to infer a bottomhole pressure at which a fracture is created. You are making precise measurements of changes in tilt (usually at the surface, but sometimes downhole). You can probably correlate substantial changes in measurement with creation of or opening of a fracture although you will likely need a relatively large fracture.
Microseismic	Possible?	Theoretically, if you cause failure of a material, microseismic events will be generated. If you create a fracture, you can potentially expect to see events envelope it. The Kaiser effect indicates that you will not have a substantial occurrence of events until you expose a medium to a stress level that it has previously seen. Unfortunately, the situation becomes more complicated when you realize that most of the events that you see occur after you stop pumping and are associated with slippage away from the fracture itself (remember that you can infer the minimum stress from the pressure required to just keep the fracture open). Maybe, there are circumstances when you can see a reduction in events below a certain bottomhole pressure. The technique is probably more useful for looking at the trajectory of fractures that you create. More reliable stress information can be determined more easily from evaluating the pressure decay trends when you stop injecting.
Real-Time Diagnostics	Yes	These are well documented in the hydraulic fracturing literature and some of the techniques can be readily adopted. A good reference is Reservoir Stimulation Economides, M.J. and Nolte, K.G. (ed.) Third Edition, John Wiley & Sons, Ltd., New York, NY (2000).

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Method	What Reservoir Properties?	Comments
Injectivity/Falloff	Average pressure, permeability, skin, fracture characteristics, etc.
Hall Plot	Permeability and skin	Process the slope information. See, for example, Earlougher, 1971.
Pulse Test	Permeability and storage.	Possibly anisotropic effects. There is a test type known as the impulse test that can be carried out to infer properties about the formation permeability. For more information on this:
Interference Test	Usually, the mobility-thickness product, kh/m, and the porosity-compressibility-thickness product, fcth	Often anisotropic behavior can be identified.
Step Rate Test	Formation pressure, permeability, skin	If appropriate multi-rate analyses are carried out, it is possible to infer permeability and skin for the matrix and possibly even estimate fracture properties by evaluating changes in skin.
Hydraulic Impedance Test	No
Production Logging Test	"All"	Essentially any formation flow properties can be identified with an appropriately conducted PLT. PLT surveys are essential for discriminating properties in multilayer situations. For additional information, you can go to the guidelines for multilayered reservoirs.
Tracers	You may be able to: Characterize of reservoir continuity. You can infer continuity and effectiveness of barriers by monitoring different tracers produced into different wells. Characterize reservoir transmissibility. Transmissibility can be estimated from tracer transit time. Identify reservoir-scale fracturing, faulting and other directional features. Identify referred injection paths.
Fibre Optics	"All"	Essentially any formation flow properties can be identified with an appropriately conducted PLT. Fiber optics will allow you have continuous PLT data. PLT surveys are essential for discriminating properties in multilayer situations. For additional information, you can go to the guidelines for multilayered reservoirs.
Leakoff Test	Little	Some qualitative information about fluid loss in the zone where the shoe is may be possible, but this information should not be relied on, if possible.
Extended Leakoff Test	Possibly permeability can be inferred.	This is a type of injection falloff test. Its primary purpose however is for identification of in-situ stresses. The volumes injected may not be large enough for easy interpretation of pressure transient data because of storage effects.
Micro/Minifrac	Permeability and damage and fracture length	If the injected volume is small, this is basically an XLOT. If the volumes are large enough and you have some method for estimating fracture geometry, it may be possible to infer fracture length, permeability and a composite indication of damage. Hydraulic fracturing technology can be applied - with caution.
Tiltmeter	None
Microseismic	Qualitative	Some possible indications of preferred directional trends and the degree of natural fracturing?
Real-Time Diagnostics	Progressive damage, tip plugging ...	For more information, refer to stimulation and mitigation.

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Method	Yes/No?	Comments
Injectivity/Falloff	Yes	Presumably, it can be particularly useful if done periodically. Expense is usually cited as the reason that these are not done. Potentially, shutdowns can be designed to acquire falloff data. If permanent downhole monitoring equipment has been installed, testing could conceivably done on a more regular basis so that decisions on the necessity for stimulation can be made more prudently.
Hall Plot	Yes	Look for slope changes not related to changing average reservoir pressure.
Pulse Test	Doubtful
Interference Test	Possible but unlikely	Must be run for a long time.
Step Rate Test	Same as falloff	Same as falloff
Hydraulic Impedance Test	Unlikely	You may see some changes in fracture impedance but interpretation will be difficult.
Production Logging Test	Yes	They may be most useful when they are chronologically c compared.
Tracers	Possible	Detailed modeling may show some indications, as can time-dependent changes in vertical or areal characteristics.
Fibre Optics	Yes	The best of all worlds. Intervention is not required. There is a continuous time profile along the target zones.
Leakoff Test	N/A
Extended Leakoff Test	N/A
Micro/Minifrac	Possible but unlikely.
Tiltmeter	No
Microseismic	No
Real-Time Diagnostics	Definitely	For more information, refer to stimulation and mitigation.

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Method	Cost?	Risk?
Injectivity/Falloff	Modest to unacceptable	Expense can be significant if isolation is required in a subsea well and there is no permanent monitoring. Downhole shutoff may or may not be needed. Downtime will always be a consideration.
Hall Plot	Minimal	One particularly desirable feature is that this continuous monitoring method can be done cheaply provided that you have a way to infer or measure bottomhole pressures and have a feeling or supplementary measurements/simulations of the reservoir pressure. Low risk.
Pulse Test	Modest	Depends on the availability of observation wells. There will be some downtime. Could be done in conjunction with other PTA programs. Probably low risk, except in some poorly or completely unconsolidated reservoirs where liquefaction of the formation near the wellbore may occur - usually pulses will be small enough that this is not an issue. Risk and expense increases if isolation is required.
Interference Test	Modest to high or unacceptable	More than one observation well is required to infer anisotropy. Regardless, an observation well(s) must be available for a moderate to prolonged period of time. Risk and expense increases if isolation is required.
Step Rate Test	Modest	Can usually be done without intervention unless isolation is required. Bottomhole pressure needs to be inferred or measured.
Hydraulic Impedance Test	Low	This test is operationally simple. Based on Heidrun experience (not with HIT but with rapid shutdown), there can be a risk of liquefaction of unconsolidated sands. Presumably, this risk can be reduced by backing off on the rate before the measurement.
Production Logging Test	High to unacceptable.	Intervention is required unless there is permanent measurement equipment (e.g., fibre optics).
Tracers	Low to modest.	HSE precautions vary according to the tracer type and program.
Fibre Optics	Moderate upfront cost. May be one of the few acceptable options for subsea completions.	Consider issues for future workovers and for perforating.
Leakoff Test	Low to modest	Will often be done regardless and the question is whether additional expenditures to make the testing more sophisticated (XLOT) should be considered. There is always a well control risk during drilling.
Extended Leakoff Test	Modest to unacceptable	There is always a well control risk during drilling. There may also be hesitation in breaking down the shoe.
Micro/Minifrac	Modest to unacceptable, depending on the need for isolation.	High risk openhole. Moderate risk of packer failure in cased hole if a zone is straddled with inflatable production packers. Some risk that you will not be able to break down the zone in various environments (very hard rock, deep, overpressured ...).
Tiltmeter	Modest to high	May not be feasible offshore unless run in the injector itself and this will have risk and attendant costs. Interpretation of in-well tlltmeter data is still in its infancy. If the survey is not run in the injector itself, observation wells or surface locations are required. There are some depth restrictions for surface monitoring.
Microseismic	Modest to very high or unacceptable.	Observation wells are required. There is presumably a future potential of using sea bed sensors.
Real-Time Diagnostics	Low	Do it and USE it. Don't forget water quality.

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