Sampling & Testing
Sidewall Coring Devices
The objectives of coring are to bring a sample of the formation and its pore fluids to the surface in an unaltered state, to preserve the sample, and to transport it to a laboratory for analysis.
These objectives are hard to meet since the very act of cutting a core will, to some extent, alter both the properties of the rock itself and the saturation of the fluids in its pores.
A number of techniques exist for minimizing the damage to formation samples. Other techniques, aimed at restoring the original state of the formation sample when it was at reservoir conditions, may also be brought into play at the time the core is analyzed.
Two methods of retrieving formation samples using wireline tools are currently in use: the conventional sidewall core gun, and a relatively new device, the core plugger.
Sidewall Cores Figure 1 illustrates a sidewall core gun; Figure 2 shows it in close-up. The body of the gun carries a number of hollow steel bullets that can be fired selectively into the formation by means of explosive charges. Once lodged in the formation, the bullet can be retrieved by means of attached flexible steel wires. By raising the gun in the borehole, the tension on the wires is usually increased sufficiently to dislodge the bullet.
Once samples have been collected, the gun is raised to the surface and each core plug stored in a glass jar marked with the well name and the depth from which it was cut. Subsequently, these cores may be analyzed for porosity, permeability, and hydrocarbon content.
Note that the gun is equipped with an SP electrode. This allows the tool to be placed at the correct depth in the well prior to sampling by correlation of a short section of the Sp log with other openhole logs already run.
These guns come in a variety of shapes and sizes. On average, they are capable of retrieving 60 samples in one trip into the hole. The diameter of the core barrel may be anywhere between 3/4 in. and 1 1/8 in. The length of the core retrieved is a function of many variables. Depending on the strength of the explosive charge used, the type of core barrel selected, and the hardness of the formation, the length of the recovered sample may be as long as 2 in., or as short as nothing at all.
There are obvious limitations to the amount of data that can be obtained from sidewall cores. In the first place, the sample is taken from a part of the formation that has been flushed with mud filtrate. Secondly, the act of explosively firing the coring bullet into the formation may induce local fracturing. Occasionally, the retainer wires used to retrieve the core barrel may sever and the bullet will be lost in the hole. Lastly, the trip up the hole to the surface involves a considerable amount of flushing through the mud column. Despite these drawbacks, sidewall cores are still good quick-look indicators of formation properties. It is normal practice to inspect these cores at the wellsite for hydrocarbon odor, fluorescence, stain, and cut if a mud logging unit or geologist's doghouse is available.
Core Plugger The core plugger uses a motorized circular bit to bore into the wall of the formation in order to retrieve samples. Currently, this tool is capable of cutting up to 12 core samples in one run in the hole. Core size is 15/16 in. in diameter and 1 3/4 in. long. Each core takes about five minutes to cut. This device works better than the conventional sidewall core gun in consolidated formations, and causes no physical damage to the sample.
Wireline Formation Testers
Wireline formation testers serve a number of useful purposes, including obtaining a sample of formation fluid, gauging formation permeability, and measuring formation pressure to determine formation pressure gradients.
Wireline formation testers have been used for many years to recover samples of formation fluid both in open and cased holes. Traditional tools suffered from a number of drawbacks, such as lack of resolution and accuracy of pressure gauges, and the inability of the instrumentation to tell the operator whether or not a good packer seal was obtained until it was too late to rectify the situation.
These inadequacies have now largely been overcome by the introduction of two key features of modern repeat formation testers, namely quartz crystal pressure gauges and pretest capabilities that allow the operator to rectify a bad seal before it leads to undesirable results. An added bonus is the ability of these tools to make pressure tests independent of sample taking. Indeed, in practice nowadays it is quite common to use these tools solely to make pressure tests.
Tool Characteristics and Applications Most service companies now offer a repeat formation tester that includes pretest chambers, sample chambers, and a high-resolution pressure gauge.
Wireline formation testers are particularly useful
- when investigating zones of interest in which conventional tests are not feasible, such as those too far above TD, those lacking good intervals for setting straddle packers, or those with very short intervals, where depth control is critical
for pinning down water-oil, gas-oil, or gas-water contacts
when rig time is critical
when pressure control is critical because of time of day or rig locations
When ordering the service, give plenty of notice to the service company. Variables such as sample size, packer hardness, choke size, pressure gauges, and water cushions may not be universally available. If a sample of recovered hydrocarbons is needed for PVT lab analysis, a special pressure cylinder should be requested.
When running the tool, a valid test is one that recovers significant quantities of fluid and/or records formation and hydrostatic pressure.
A dry test is indeterminate, and the tool should be repositioned several times to determine whether the formation is impermeable (in which case all tests will be dry) or the tool was set in a shale or tight streak (in which case repositioning should result in a valid test).
A lost packer seal is also indeterminate. In that case, the tool should be repositioned. Openhole logs are particularly helpful in resolving dry tests and lost packer seals. The microlog, if available, is useful as an indicator of tight streaks, and caliper logs, particularly the four-arm type, are useful for avoiding hole conditions leading to lost packer seals.
Operating Principles Figure 1 shows the RFT tool in the closed position (a) for descending into the well, and in the open (set) position (b) for pressure measurement and sample taking.
Communication between the formation and the tool interior is established through the probe. Figure 2 is a schematic of the tool's sampling system. Note the details of the actuation of the filter probe: in the setting cycle it is forced to cut through mudcake, and in the sampling cycle it is retracted to open the path for formation fluids.
Note also the pretest chambers and the position of the sample chambers. The two pretest chambers, automatically activated every time the tool is set, withdraw 10 cc of formation fluid each. Chamber 2 has a higher flow rate than chamber 1. The actual rates of fluid withdrawal vary with the tool and the downhole conditions but are approximately 50 cc/min for chamber 1 and 125 cc/min for chamber 2, resulting in pretest times of roughly 12 seconds and 5 seconds. The pretest samples are expelled back into the mud column and are not saved.
Figure 3 shows a typical log produced during a test. Since the tool is stationary in the hole during the test, the recording is made on a time scale with increasing time in the down-hole direction on the log. Notice that in track 1, pressure is recorded in analog form. Four subtracks record the units, tens, hundreds, and thousands of psi.
Each record shows the following pressures:
· before tool is set--hydrostatic
· during pretest--drawdown
· after pretest--buildup
· after buildup--formation pressure
The standard gauge used in the RFT is a strain gauge calibrated by a "dead weight" tester. The accuracy of this system, after applying temperature corrections, is 0.41% of full scale, i.e., 41 psi for a 10,000 psi gauge. The resolution of the gauge is about I psi, with a repeatability of 3 psi. The accuracy may be improved to 0.31% full scale if a special calibration technique is employed involving placement of the gauge and the downhole electronics in a temperature-controlled oven.
Where greater accuracy is required, a high-precision quartz gauge may be used. The accuracy is then 0.5 psi, provided that the temperature is known within 1 C. Resolution is on the order of 0.01 psi.
It should be noted ( Figure 4 ) that the quartz gauge is located lower in the tool than the reference measurement point that is the strain gauge. Hence, the pressure recorded by the two gauges is different due to the hydrostatic head of a column of silicone grease. In some cases, a further pressure difference may be noted between the two gauges, since the strain gauge is calibrated in psig and the quartz gauge is psia.
Interpretation In order to make the greatest use of RFT data, the analyst should be able to interpret the following types of RFT records:
- pretest records for formation permeability
- post pretest buildup for formation permeability
- large-sample fill-up time for formation permeability
- sequential pressure readings versus depth for pore pressure gradients
- large-sample collection data for expected formation product ion
Pretest Records for Formation Permeability Figure 5 shows a typical pretest record. In reality, only one pretest is required to estimate formation permeability. The magnitude of the pressure differential (DP) between pretest sampling pressure and formation pressure coupled with the flow rate during pretest is sufficient to define permeability. In general, this may be found by a relation of the form
k = A • C • q • µ / DP
where:
k is permeability in millidarcies
A is constant to take care of units
C is the flow shape factor
q is the flow rate in cc/second
µ is the viscosity of the fluid in cp
P is the drawdown in psi
A number of flow regimes may exist around an RFT tool and the borehole. It is generally agreed that the flow is somewhere between hemispherical and spherical. Computer modeling of the probe/formation system for one service company's tool shows that the combination of constants A • C to be used should be such that
The flow rate is derived by dividing the 10 cc volume of the pretest chamber by the sampling time read from the pressure record. The viscosity, µ is considered to be that of the mud filtrate and may be estimated from published charts. DP is read from the pressure recording as the difference between pretest sampling pressure and formation pressure.
The pretest method of permeability determination has these limitations:
- If the permeability is very high, the drawdown is very small and cannot be measured accurately.
If the permeability is very low, the sampling pressure may drop below the bubble-point, in which case gas or water vapor is liberated and the
flow rate of the liquid withdrawn is less than the volumetric displacement rate of the pretest pistons.
The volume of formation investigated is small and hence the permeability measured may be that of the damaged zone, if present, and thus not representative of the formation as a whole.
In general, a good estimate of formation permeability may be obtained from a visual inspection of the pretest record.
Post Pretest Buildup for Formation Permeability Permeabilities obtained from pretest may be subject to the errors mentioned above; they also may not be measuring absolute permeability but the relative permeability to the water in the flushed zone. Figure 6 marks the pretest region on a set of relative permeability curves, from which it can be deduced that the pretest permeabilities are less than half absolute permeability when measured in an invaded oil zone.
A preferred method of calculating permeability is the analysis of the late-time portion of the pressure buildup record after the pretest disturbance has been made. A much larger rock volume can be investigated in this fashion. The method effectively measures kro close to Swirr, very close to k absolute (see Figure 6 ) when the measurement is made above the transition zone.
Figures 7a and 7b illustrate two modes of propagation of a pressure disturbance; Figure 7a is for spherical propagation and Figure 7b for cylindrical propagation. In a thin bed, the cylindrical mode predominates, whereas in a thick bed the spherical mode prevails.
In order to determine whether cylindrical or spherical flow is predominant in a test, the pressure may be plotted against one of two time functions, respectively derived on the assumption of cylindrical and spherical flow. The characteristics of these time functions are such that a plot of pressure versus the relevant time function for the actual flow regime involved produces a straight line whose slope is proportional to the formation permeability and whose intercept at the zero time point gives the formation pressure. Figure 8 gives an example of such time-pressure plots.
Large-Sample Fill-Up Time for Formation Permeability When a large sample of formation fluid is recovered, the time taken to fill the sample chamber can be used as an indicator of permeability. Drawdown is here considered to be the formation pressure itself, since the sample chamber is for all practical purposes at atmospheric pressure. This may not hold true if the fill-up time is limited by a water cushion and a choke. Use this method with discretion and take it for what it is: a quick and dirty way of finding permeability.
For one service company's large sample chamber, the following equation may be used:
where:
k is fill-up permeability in mud
C is flow-shape factor
q is flow rate in cc/sec
µ is fluid viscosity in cp
P is drawdown pressure in psi
Sequential Pressure Readings versus Depth for Pore Pressure Gradients Since many formation pressure measurements may be made on one trip in the hole, pressure gradients can be calculated and plotted. The easiest method is to plot formation pressure against depth. It is useful to plot hydrostatic pressure on the same plot.
Gas-oil and oil-water contacts are evident on a plot of this nature. The fluid density can be deduced from the pressure gradient, by using
fluid density gm/cc = pressure gradient (psi/ft) • 2.3072
Care should be taken in low-porosity transition zones where capillary pressure effects are pronounced. Log-derived oil-water contacts (OWC), for example, may appear somewhat shallower in the well than the free water level indicated from plots of formation pressure versus depth.
Formation Production Estimates When a large sample is recovered, it is possible to predict formation productivity by analysis of the recovered oil, water, and gas. At the surface a miniseparator is used to measure the volumes of oil, water, and gas recovered ( Figure 9 ). The water recovered will be a mixture of mud filtrate and formation water. The amount of formation water is calculated from the relationship
%
Empirical charts then link recovered volumes to predicted production. Three areas are delineated on the chart indicating formations that are gas, oil, and water productive. An estimate of water cut can also be made using
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