Formation Testing, Permeability Measurement, Well Testing, Packer Testing
What is it?
These four titles are synonymous for what is essentially finding the properties of the formation that affect how fluid flows through the ground whether it is a gas reservoir, an aquifer or the rock around an excavation.
Sigra conducts such testing for the petroleum, mining, civil and groundwater industries
The process involves causing flow to occur and finding out the pressure changes that are associated with that flow. The test methods involve pumping from or injecting into a well and measuring the pressure change in that well or in surrounding monitoring wells during the flow and recovery periods.
Because of the varying depths and fluids the test processes may differ but the fundamentals remain the same. The nomenclature used in different disciplines varies. Petroleum engineers work in centipoise for viscosity and milli-darcies for permeability. Groundwater Engineers will mix the two with density and create a unit known as permeability or more correctly, hydraulic conductivity.
Summary of Formation Testing with Some References to Coals
In-situ permeability testing is undertaken to obtain a measure of the permeability in the ground. It invariably involves measuring flow from or into a well. In addition it involves the measurement of pressure. This is normally conducted within the test well, but may also be undertaken in observation wells.
When undertaking a permeability test the issues that need to be considered are:
- Is the geometry of the formation being tested known? This covers all the different types of boundary such as faulting, thinning or recharge. It also covers the adjacent formations. Are they sealing, gas caps, aquifers or fluctuating phreatic surfaces? Without knowledge of geometry the analysis of the well test may be completely erroneous. Frequently however, the results of well testing help provide the clue to the geometry of the reservoir.
- How many phases (gas, water, oil) exist in the reservoir being tested? The uniqueness of solution of a multi-phase test is always in doubt. It is far better to test with the predominant phase. For coals in their original state this usually means water, as most coals are normally water saturated until the pressure has been lowered and gas is desorbed.
- Is the permeability directional? Most coals exhibit significant directional permeability.
- How does the permeability vary during production or drainage? Coals generally show a very pronounced relationship between the effective stress and the permeability. It is possible for coals to change their permeability by an order of magnitude if the pressure within the seam is lowered by a few Mega Pascals.
- What is occurring near the test well bore? The behaviour of the formation near the well bore is generally different from that of the rest of the reservoir. This may be due to:
- Drilling fluid invasion changing the viscosity of the fluid adjacent to the well.
- Particulate matter entering the pore space or cleating adjacent to the well and changing its permeability.
- Effective stress changes near the well bore changing the permeability of the formation. This applies particularly to the case of coal.
- Loosening of the formation adjacent to the well bore leading to enhanced permeability near the well. This case applies particularly to gravels and sands which loosen as they relax on to a screen.
- Non-linear flow effects near the well bore. In higher permeability reservoirs it is possible to have high enough flow rates that the flow adjacent to the well bore becomes turbulent.
- Phase variation near a well bore. In the case of coals it is possible to lower the pressure for a long enough period that gas is desorbed from the coal. Because of the multi-phase effects the gas may partially block the movement of water towards the well bore.
- Well bore storage may be important in well tests where the flow rate into the well is small compared with the well volume. This is the case for liquids where the well loses and gains fluid volume with changing liquid level, or in the case of gas wells because of the change in stored volume with different pressures within the well.
- The radius of investigation of a well test matters as it is important to know how representative a volume of formation is being tested. If the volume is too small the result of a test may simply represent the mud damaged or stressed zone around the well. If it is large then it gives confidence to the result. The higher the permeability and the longer the test then the larger the zone influenced. Sigra uses the concept of the mean effective radius of investigation to characterise the zone tested.
The Analysis of Well Tests
Well test analysis enables the determination of permeability, reservoir pressure, the degree of near well bore permeability damage and the radius of investigation. This is most easily achieved by testing a well with a single flow rate followed by a build-up period during which no flow takes place. If the test is prolonged, its overall pressure reduction (draw down) may be observed and some estimate made of the reservoir size. Where observation wells can be used additional information may be gained on the storage behaviour and directional permeability of the reservoir.
Being able to de-convolute a complex multi-rate test is theoretically possible if the reservoir properties remain absolutely constant and the geometry of the reservoir is known. It is however in most real cases an undesirable complication. This applies particularly to the case where the near well bore pressures vary widely, with the flow rates causing changes in effective stress and permeability in the near well bore area. If additional information is sought on near well bore effects, it is best to conduct a single rate test with recovery followed by an independent step rate test.
Types of Tests
In any measurement it is necessary to keep practicalities in mind. The first is in maintaining the simplicity of any test procedure. The second is in ensuring that the test produces results that can be analysed.
Single Hole TestsThe testing is accomplished totally within a single hole. These tests can, if conducted properly, be analysed to provide information on the geometric mean permeability and, with assumptions, on the near well bore loss behaviour of the well. A test in a single well cannot be analysed to provide reliable estimates of the storage terms within the reservoir such as the compressibility porosity product, storativity or specific yield.
Multiple Hole Well TestsTo provide information on directional permeability and storage terms, Multiple Hole Well tests can be used, provided that some of the wells are used as observations wells. These tests may be of multiple forms. The most common is of a single flowing well surrounded by other wells that contain piezometers to determine the changing fluid pressure therein. Alternatively it may be made up of multiple wells which are flowed sequentially and observed in other wells. The flow process may be at a single rate in which case the information on the reservoir is obtained from the pressure change with time. Reservoir information may also be gained by producing or injecting in a pulsed manner, and observing the time shift of the arriving pulse.
Slug TestsSlug tests are the simplest test that can be conducted. A volume of water is poured into the well and the level of the fluid lowers as flow out into the formation takes place. To be able to conduct this type of test the potential head in the formation must be below surface level. It is a variable flow rate test with varying pressure in the well. Because of the direction of fluid flow the fluid introduced to the reservoir is not reservoir fluid and may not have a similar viscosity. It may also contain particulate matter which leads to clogging of the cleats or pores adjacent to the well bore. These effects and the changing well pressure lead to variable near well bore effects that cannot be separated analytically from the reservoir behaviour. Notwithstanding the work of Hvorslev (1951) and others since, these tests cannot be reliably interpreted.
Packer TestsThe civil engineering industry has used packer tests for many years. The basic technique was put forward by Maurice Lugeon (1933). In this a section of borehole is straddled by packers and water is injected with 1 atmosphere pressure at surface. The hydraulic conductivity is expressed in terms of the Lugeon value, which is empirically defined as the hydraulic conductivity required to achieve a flow rate of 1 litre per minute per metre of test interval under a reference water pressure equal to 1 MPa. If the flow rate is higher the Lugeon value is proportionately higher. This sort of test takes no account of the initial fluid potential (level) in the hole. It also assumes that the flow rapidly becomes steady state and it takes no account of near well bore effects. These three assumptions mean that the test results are not interpretable in terms of real values of permeability. The method has some use in empirically defining the degree of fracturing in the rock mass being tested, but should not be interpreted beyond this.
Pumping TestsThe standard test used by hydrogeologists is a pumping test. These are normally conducted at a constant rate as this leads to the most straightforward analysis. In cases where the permeability is low a significant proportion of the fluid produced may be made up from well bore storage. Setting the flow rate at the start of the test is always a problem and in lower flow rate cases it is frequently difficult to hold a constant pumping rate with adequate precision. If a constant rate can be maintained good results may be found with prolonged pumping. This is particularly the case if observation points fitted with piezometers are spaced around the pump well. In this case well bore loss terms become irrelevant and the formation parameters of permeability and storage terms may be determined.
A pumping test may also be performed at a constant pressure in the well. Such a test is suitable for an artesian bore which produces to atmospheric pressure at the surface. The analysis of such a test with observation wells is straightforward but for the case where the test is totally conducted in the producing well, a varying flow rate complicates the determination of near well bore effects.
Long term pumping tests with significant pressure reduction in coals may lead to the production of gas through desorption. In this case the analysis becomes complicated as there is no definitive process to deal with.
Pumping tests that are followed by a non-producing recovery period are particularly valuable as the pressure build-up is determined without the effects of significant flow into the well. Thus the well bore loss terms can be eliminated from the analysis.
Interference TestsThese tests may be regarded as the petroleum term for pumping tests in which the producing well has several pressure transducers in surrounding wells to monitor the effects of production. Sometimes however an interference test may be conducted by injection. Whilst injection will remove the risk of two phase flow in most coal reservoirs it runs the risk of well bore damage through the injection of foreign fluids or clay penetration into the cleats.
Drill Stem Tests (DST)Drill Stem Tests constitute a simple form of production test. The test involves isolating the formation to be tested by packers. Above the packers is a partially empty drill string. Once the pressure in the test zone has stabilised a valve situated between the test zone and the drill string is opened so that the fluid from the formation flows into the string. The volume of fluid is determined by the pressure change of the fluid in the string and by the measurement of gas flow at surface. After a flow period the valve is shut and the pressure build up is monitored. This build up period is measured with zero flow and is therefore free of near well bore effects.
In coals it is generally found that there are significant near well bore pressure losses which mean that the inflow rate to the well is governed more by these effects rather than the permeability of the coal seam. The inflow rate to most DSTs in coal is therefore nearly constant. If the inflow time and the pressure drop is limited then gas desorption from the coal is not a major issue in the test process. The analysis of the test is based on flow rate, flowing time, and the slope of the pressure versus log time build up plot. If an assumption is made about the storage terms of the formation then the well bore loss terms may be determined.
The early pressure response following shut in of a DST test often provides an indication of the effective stress – permeability characteristic of a coal seam and the late pressure response is a function of the undisturbed reservoir permeability.
Injection-Fall-off TestsThe procedure for performing an Injection Fall-off test involves injecting into the formation to be tested for a period, after which flow is stopped and the pressure decline characteristic is measured. The analysis is the same as for DSTs. The limitations on the test come from the injection of non-reservoir fluids and the possible well bore damage due to the ingress of particles into fine pore space or cleats.
Falling Head with Shut InA variant of the injection fall off test is the falling head with shut in test. It is suitable for reservoirs with low pressures (heads). It involves filling the drill string with a liquid above a test zone isolated by packers. Once a stable pressure has been reached in the test zone the valve is opened and flow takes place from the string into the formation. The valve is then shut and the test zone pressure is monitored while it stabilises. The test is the injection equivalent of a DST.
Step Rate TestsTo determine the non-linear well bore production characteristics usually associated with laminar and turbulent flow step rate tests are used. In this the well is usually pumped at three stepwise increasing rates for a long enough period that a linear pressure (head) decline rate with respect to log time can be determined. An alternative view of a step rate test is to inject at a stepwise increasing rate until hydro-fracture of the formation takes place.
Diagnostic Fracture Injection TestsFor low permeability reservoirs DFIT (Diagnostic fracture injection test) tests can be used. The test process involves pumping fluid into a test zone at sufficient pressure and rate that the reservoir is fractured. Pumping then ceases and the pressure decline is monitored. The decline is analysed for a linear period when the fracture is leaking off and closing, and for radial flow behaviour long after fracture closure. The linear flow analysis is complicated by the fact that the fracture size and geometry are unknown. The test method has become popular simply because some flow can be induced into what would otherwise be a reservoir that is too impermeable to flow. It overcomes the problem that a well that does not flow has an undefined permeability – whether the solution is reliable is another matter.
Pulse TestsPulse Tests involve pumping from or into a well and monitoring the pressure changes in observation wells. They are particularly suitable for high permeability reservoirs and where there is not time to wait for the pressure change characteristic to be visible in the observation well. The analysis of pulse testing is based on the time delay between the production pulse and the observation of the pressure pulse from it. The pulse is usually repeated to gain some certainty of the result. Pulse testing between a number of wells enables directional permeability characteristics to be determined. Pulse tests require very sensitive pressure transducers and zero well bore storage in the well in which they are used.
Multiple Well Tests in GroupsThese may be used to determine the behaviour of a reservoir advantageously. In this case production or injection is carried out in each well and the effect of that well is observed in the adjacent wells. It provides multiples of the information that would be obtained from a single interference test with the particular benefit that there are adequate flowing wells to permit a statistical determination of reservoir parameters. It avoids problems with the case where a single producing well is located in a particularly high or low permeability zone.