Well testing john lee pdf free download

If possible, no well that is producing water should be considered for obtaining a representative hydrocarbon sample. If necessary, a water-producing well may be sampled if precautions are taken to obtain the sample from above the oil-water contact in the well or separator. Wells that have or may have gas coning into the production interval should be avoided as candidates for sampling. Flowing eruptive wells are the best candidates for fluid sampling.

Production rates are more easily controlled, and measuring the bottom hole pressure is practical. In contrast, subsurface sampling on a pumping well requires the removal of the pump and rods. For obvious reasons, wells on continuous gas lift are unsuitable for surface sampling procedures.

However, if a gas lift well will flow at low rates on its own, it may be conditioned and sampled the same as any flowing well. A flowing oil well is conditioned by producing it at successively lower rates until the nonrepresentative oil has been produced. The well is considered to be conditioned when further reductions in flow rate have no effect on the stabilised gas-oil ratio.

This gas may be present due to coning the drawing down of the free gas cap into the producing interval or due to the flowing bottom hole pressure being less than the bubble point pressure. The lower drawdown allows less oil and relatively more gas to flow from separate intervals. Such wells should not be sampled, because it is very difficult to determine when they are adequately conditioned.

This irregular flow makes it difficult to measure the GOR accurately. Some wells may have such low productivity that even a low flow rate requires a large drawdown.

A gas condensate well is also conditioned by flowing it at successively lower flow rates and monitoring the GOR. The GOR should generally decrease as the rate is decreased. This is because Introduction to Well Testing March Section 4 Sampling of Reservoir Fluids the lower rate results in a lower drawdown, which brings the wellbore pressure back out of the twophase region. The heavier hydrocarbons will be produced rather than condensed in the reservoir, thus increasing the liquid volume at the surface and decreasing the GOR.

When the GOR stabilises, the well has been conditioned for sampling. The duration of the conditioning period depends upon the volume of reservoir fluid that has been altered as a result of producing the well below the bubble point pressure, and how quickly it can be produced at low rates. Most oil wells that have not been produced for a long period of time require little conditioning; however, some wells may require up to a week of conditioning to achieve stable GORs.

The main difficulty, while sampling on surface, arises from the fact that liquid and gas are in dynamic equilibrium inside the separator.

Any drop in pressure or increase in temperature of the separator liquid, which is at its bubble point, will result in the formation of gas. For the separator gas, which is at its dew point, any increase in pressure or decrease in temperature will result in the Introduction to Well Testing March Schlumberger condensation of heavy components.

In such a case, when a fluid is diphasic during the sampling operation, it is possible that disproportionate quantities of the two phases will be collected and the sample will not be representative.

Also, before any surface sampling is attempted, the sampling point should be checked to ensure there is no possibility of contamination oil or gas condensate carry-over for a gas sampling point; water or sludge for a liquid sampling point.

If the well is under chemical injection glycol, methanol, inhibitors If it is impossible to operate without chemical injection, then the chemical used and injection rate must be recorded.

Generally, a bottom hole sample is preferred if gas and oil surface measurement capabilities are in question. However, if they are reliable, the surface sampling technique can give a statistically valid value of GOR measured over a long period of time.

Whenever possible, separator liquid and gas samples should be taken simultaneously in order to have the same sampling conditions for both fluids. Oil gravity. Gas gravity. Flowing reservoir pressure at one or several flow rates pwf. Introduction to Well Testing March Section 4 4.

In a dry gas reservoir, the gas always remains entirely in gas phase, whether at reservoir or separator conditions. A depletion from initial to abandonment pressure will not affect its state and the composition of the well stream will be constant. In a wet gas reservoir, the gas also remains entirely in gas phase in the reservoir at reservoir temperature.

A depletion from initial to abandonment pressure will not affect the state of the reservoir fluid, or its composition, which remains constant. However, at separator conditions, the well stream will be in two phases, liquid and gas. The temperature drop between the reservoir and the separator causes the heavier gas components to condense as a liquid.

At separator conditions, the production is always in two phases. Very often, wet and gas condensate reservoirs have a very similar behaviour and it is sometimes not possible from well testing data alone to decide which type of reservoir it is. Introduction to Well Testing March Schlumberger 4. Furthermore, in gas reservoirs, sampling should always be done at the surface, any separator liquid and the gas being recombined in the laboratory.

Surface sampling methods are the same as for oil reservoirs. Bottom hole sampling is unsuitable for the following reasons; a In the case of bottom hole gas sampling, the liquid condensed in the bottom hole sampler, when removed from the well, can never be completely transferred from the sampler to the shipping cylinder. Very often, the amount of this condensate is very small only a few drops wetting the walls of the sampler and during transfer at atmospheric temperature, part of it will remain in the sampler, the transferred sample thus not being representative.

Even if the sampler is heated to reservoir temperature, complete liquid re-vaporisation could take a very long time and be impossible to check at the wellsite. In such a case, the only solution is to send the sampling chamber, well secured inside a special transportation container, to the PVT laboratory.

The laboratory will then be able to transfer and check the sample. In addition to proper reservoir sampling conditions, the surface sampling of gas wells will require another condition; the liquid condensed in the production string, between the bottom of the well and the surface, should be completely removed from the well and produced in the separator. This condition will be satisfied if the gas velocity is high enough to carry the liquid phase.

The charts in Figure give such minimum gas flow rates versus well head pressure for different tubing sizes. Well conditioning is the same as for surface sampling of oil wells.

Under these conditions, even when the dew point pressure is equal or very close to the initial static pressure, and when the flowing pressure is slightly lower than the dew point pressure, samples will be acceptable. Due to these difficulties, these reservoirs should be sampled as gas condensate reservoirs and the PVT analyses will show what kind of fluid Introduction to Well Testing March Section 4 Sampling of Reservoir Fluids it is.

If proved to be an oil reservoir, then bottom hole sampling can also be done as for oil saturated reservoirs. This will help select the sampling point and confirm the validity of the well conditioning. This will insure that the well conditioning remains valid during the time required for filling the sampling chamber s. Real time surface read out of downhole recorders is the best option, but it requires the availability of a mono-conductor wireline unit.

In addition the availability of in-situ fluid density measurements is also beneficial. Otherwise, a pressure and temperature recorder should be included in the tool string. The bottom hole sampler, is run in hole in the same way as any downhole production tool. No possibility of obtaining reservoir characteristics from well test data Not advisable Smallest possible flow rate but compatible with homogeneous flow in the tubing, separator stability Whether sample is representative will only be known after PVT study.

The best field procedure is to measure the pressure in the sampling chamber, prior to transfer, and establish a Pressure-Volume curve from which a field bubble point pressure can be determined. Consequently, at least three samples should always be taken and compared. It will also affect the reproduction of the pressure curve and therefore the validity of comparing a duplicate sample.

Figure shows the pressure-volume plot of a sample in which diphasic fluid was re-compressed to psi. The pressure is recorded together with the cumulative volume of hydraulic oil transfer fluid that was displaced from the system at each step. No agitation of the sample was performed. Figure corresponds to the same procedure as in Figure , except that the sample was rocked at 90 degrees for times at each step. This oil sample example clearly shows how the lack of agitation can result in wrong and arbitrary field apparent bubble point pressure estimation.

Introduction to Well Testing March Section 4 Sampling of Reservoir Fluids Pressure psig 0 0 5 10 15 20 25 30 35 40 Volume of recovered oil 45 50 55 60 65 cm3 Fig. Laboratory analyses frequently give reduced H 2S concentrations due to these phenomena.

Thus in such cases where hydrogen sulphide is present in a reservoir fluid, on-site analysis even by Draeger reactive tubes is highly recommended. Concentrations in all produced fluids should be determined. Open Hole Sampling from Formation Interval Testing Although primarily an open hole logging device for confirmation of formation fluid and indications of productivity and formation pressure, the formation interval testing tool can also collect fluid samples for laboratory analysis.

The main advantage of this technique is that it gives an early set of samples giving some preliminary estimates before the well is cased and the reservoir produced. The main drawbacks are that the samples collected are generally from the near wellbore formation and may not contain fluids representative of the actual hydrocarbon reservoir.

This being said most tools on the market, while capable of catching large samples, even if the well does not flow to surface, are generally not capable of trapping samples suitable for full PVT analysis. Discussed in section 3. A sample regulator ensures that the sample is acquired in a controlled manner to avoid gas being drawn out of solution. The sample is trapped in a detachable chamber which can be sent directly to the laboratory or alternatively the sample can be transferred to a shipping bottle as previously described.

Downhole pressure and temperature measurements either from downhole recorders or in real time can be easily combined with the sample procedure, ensuring correct well conditioning and suitability for sampling.

Circulation type samplers are run in hole open and the open sampling chamber must be cleaned up with downhole fluid once the sampling depth is reached. While open, the tool must never go deeper than the sampling depth and the clean up is achieved by moving the tool up and down slowly for at least 5 minutes above the sampling depth.

The main advantage of this type of sampler is the removal of the risk of any gas coming out of solution during the sampling process, the main disadvantage is the risk of the sample chamber not being clean. Admission type samplers are run in the hole closed.

Once at the required sampling depth, they are activated either by battery and down hole clock pre-set at surface for operations on slickline or via an electrical signal sent from surface. This in turn either sets off a small detonator which shears a plug thus allowing the sample to enter the chamber or operates a solenoid valve. The sampling is done via the sample pushing on a piston which forces clean hydraulic oil through a regulated orifice to avoid gas breaking out of solution.

When sampling is complete a sealing system is automatically activated. Introduction to Well Testing March Schlumberger Admission type samplers are the most common used in the oilfield and many variations on their design exist.

In order to maintain the representivity of the transferred sample, the transfer must be performed at constant pressure and in single phase above the bubble point or dew point.

Transfer benches must first enable a correct measurement of the bubble point pressure before any transfer may actually be started. Modern transfer benches are designed for use with mercury free systems. In addition, vacuum pumps and hydraulic pumps are required for bottle preparation prior to sampling.

Modern systems can be provided which consist of self contained modules complete with automatic flow control and monitoring equipment to confirm the quality of the sampling process. With such systems the sampling process is practically automated.

As such, they are subjected to stringent regulations in terms of design, manufacturing, testing, certification, operation and transportation. They should only be handled by fully trained personnel. There are many types of designs for gas bottles each with their own merit.

The most practical feature being ease of handling and transportation. They are therefore much more rugged in design than gas sample bottles but nevertheless still subjected to stringent regulations.

The one key factor with oil sample bottles is to ensure that a safety gas cap is made in the bottle after sampling as the internal pressure can very quickly rise with temperature for a fluid under monophasic conditions.

As with gas bottle there are many different designs available the key points to note, are the ease with which an oil bottle can be cleaned and the elimination of as much dead space as possible. New bottles are almost entirely mercury free; either piston displacement types or membrane types. Whereas this technique solves many of the disadvantages discussed throughout this section, extra care must be taken as the equipment uses some form of nitrogen pre-charge which requires highly trained personnel to operate it.

Another technique currently under development, is that of Inert Bottom Hole Sampling — this involves the use of sophisticated metals which will not allow absorption of gases from the sample into the body of the sampling tool. These correlations can provide reasonable estimates given that the chemical nature of the fluid under test is similar to the one of the fluids that have been used for developing the correlation.

The rapidity in obtaining answers at no cost is the advantage of this approach. There is however, a considerable risk concerning the accuracy of these predictions as is shown in the example in Figure where the estimations for pb bubble point pressure in psia and Bo oil formation volume factor in reservoir barrels per standard conditions barrel given by three of the best known correlations are compared with the values measured in the PVT laboratory.

In addition correlations can only provide data limited to certain conditions e. This service can be performed on downhole reservoir samples as well as on the surface gas and liquid samples taken form the separator. Simple measurements of key physical properties, specially selected to characterise the reservoir fluid, are performed on-site with easily operated portable equipment.

These measurements are used as calibration points to tune an Equation-of-State EOS based simulator which runs on the field computer. The tuned thermodynamic model is used subsequently to predict the phase behaviour of the fluids at reservoir, well and surface conditions, and thus to generate the principal PVT data necessary for the preliminary reservoir and production engineering calculations. Introduction to Well Testing March Section 4 Sampling of Reservoir Fluids Hence by providing predictions based on measurements, the fluid properties estimator combines the simplicity and speed of the correlation approach with the accuracy of a portable PVT lab.

The service takes less than 3 hours to perform once a sample has been brought to surface. While Figure shows the same for a surface sample. Compositional analysis of the reservoir fluid is a key component of a PVT analysis and has several applications in reservoir and production engineering.

The most important application is establishing how much gasoline, kerosene, fuel oil and bitumen will be extracted when refining a barrel of crude oil. It also dictates how and where the oil will be refined. Another application is detecting corrosive compounds that require special consideration when defining production and transportation equipment. Composition is also required as an input to equation-of-state simulators used for reservoir description.

Techniques used include gas chromatography, distillation and micro distillation and mass spectrometry. Fluid pb T amb. Equation-of-State Simulator Match Points pb at res. Gas Comp. The value of the overall constant depends upon the units. Introduction to Well Testing March Schlumberger 5. The upper and lower bed boundaries are parallel and clearly defined, the reservoir rock between them is homogeneous, and the wellbore is perpendicular to the bed boundaries: Fig.

Dimensionless variables are designed to eliminate the physical parameters that affect quantitatively, but not qualitatively, the reservoir response. The above equations are in Darcy units, and the dimensionless terms will render the system of units employed irrelevant.

For this simple line source model, 3 dimensionless variables are required. This change of variables can be performed on problems of any complexity, but this may require additional variables, such as in this case skin factor, dimensionless storage, etc. For this reason the Line Source solution is sometimes called the Exponential Integral solution. Skin is described in the next section. Introduction to Well Testing March Section 5 5. The linear or Cartesian plot of pressure versus time, as shown above, is of limited value in well testing, but does have specialized uses, as will be seen later.

Well test interpretation is predominantly carried out using semi-log and log-log techniques. Initially, flow at surface is due only to decompression of fluid in the wellbore. Eventually, decompression effects become negligible and the downhole flowrate approaches the surface rate: Fig.

This is known as afterflow, and is also called wellbore storage. The principle is the same as for the drawdown, and it will be seen later that the effect on the pressure response is identical. Until storage effects are over, the pressure response alone will contain no useful reservoir information.

This mathematical description is not very realistic, as in real wells there will not be two discrete regions, each with homogeneous properties and with clear boundaries between the two. As long as the perforations are big enough, deep enough, and of a sufficiently high shot density and phasing, the pressure drop flowing into the well may still not exceed the pressure drop in the ideal case.

The situation can usually be improved by acidizing. In exceptional cases there may actually be an over-sized hole outside the casing, but typically this would not be the case. The skin value will be seen to do more than simply influence the pressure drop during production. For example, a high skin delays the onset of radial flow information in the pressure data, and a negative skin brings it forward.

This is due to the inter-dependence of skin, productivity and wellbore storage effects. In other words, if pressure is plotted against the log of time, infinite-acting radial flow will give a straight line.

Semi-log plots are discussed in detail in section 5. The straight line representing radial flow is established almost instantaneously, and from the slope of the line the permeability-thickness product, kh, is obtained. Initially production is only from decompression of the wellbore fluid, so the bottomhole pressure remains constant for a short while, as if the well were still shut in.

Once there is movement of fluid through the sand face, the bottom hole pressure starts to drop, and once the effects of storage are over the red curve transitions onto the ideal curve. The storage causes the delay, the skin the offset, and once again the final straight line slope is unchanged, as permeability is a reservoir property and is unaffected by near-wellbore effects. In most cases the pressure curve will eventually drop below the radial flow line, as shown to the right of the grey window, if the well is tested long enough.

This is because there is no such thing as an infinite reservoir, and as boundaries are seen, but the same flowrate is maintained from the well, the pressure will drop more rapidly.

Sometimes the opposite happens, and the boundary is a supporting aquifer or gas cap, in which case the pressure curve tends to stabilize. What is certain is that the radial flow, and its corresponding straight line, can not last forever.

Until the effects of wellbore storage become insignificant, the pressure response does not reveal information about the reservoir. As mentioned previously, this example is for the simplest semi-log plot, the MDH drawdown plot. However all of the principles described apply equally well to the other semi-log plots, as discussed in section 5.

Changing values of the constants in the groups A and B will cause the data to be shifted on the X and Y-axes, but the curve shapes will remain unchanged. Once a model has been identified, and a match established, the displacement between the actual data and the dimensionless type-curve on both X and Y axes provides solutions for some interpretation parameters.

Typically, wellbore storage C is evaluated from the time match, or X-shift, and permeability-thickness product kh from the Y-shift. The type-curve solution match provides the skin S. When the actual pressure data is plotted on the same graph as the dimensionless type-curves, it is offset in the X and Y-directions: Fig. The pressure derivative is essentially the rate of change of pressure with respect to the superposition time function — i.

The data starts at point 1, before eventually stabilizing at slope m in Infinite-Acting Radial Flow, points 6 and 7. The transition is complete at point 6, as the derivative flattens to a value equivalent to m. For most other flow regimes, it will be seen that while the log-log plot reveals little or no relevant information, the pressure derivative always displays a characteristic response.

The concavity around the well will reduce in time, as more and more of the fluid is produced from further into the reservoir. This produces a build-up pressure profile which is convex around the wellbore pressure increasing and concave everywhere else pressure still decreasing due to the still-diffusing production signal. Considering an interference well, i. At this point the pressure will start increasing again, to ultimately reach initial pressure in the case of an ideal, infinite reservoir.

This distortion will diffuse and will be progressively absorbed by the overall pressure profile, originally affected by the previous production. Outer Boundaries Any outer boundary will provide a fixed profile no flow or a fixed pressure, which will become important when the pressure profile induced by the production conflicts with this condition. At such a time, boundary effects induce an additional distortion of the flow profile, which will also diffuse, to ultimately reach the well.

The distortion in the pressure profile can be identified as due to a boundary, as will be seen in section 5. This analytical model was developed assuming a single constant production rate, whereas in practice we need to obtain a model solution for more complex flow histories. In particular, due to the difficulty of maintaining a constant flow rate, interpretation methods have traditionally been based upon build-up data, preceded of course by one or more drawdowns.

The superposition principle allows the multi-rate response to be calculated simply by adding drawdown responses. The shut-in at time tp is mathematically equivalent to a continuation of the drawdown at rate q, in combination with an injection at rate -q from time tp: Fig.

A sequence of rates q1, q2, All wells in the same system can be added to obtain the total response at any point in the system. This principle is used in interference testing, and can also be used to model sealing and constant pressure boundaries: Fig.

Although not physically rigorous, the idea of a reflected signal can be used to explain the principle. In the real case, with one flowing well and a fault, the measured pressure response at the wellbore becomes a combination superposition of the drawdown response and the reflected response returning from the fault: Introduction to Well Testing March Schlumberger Fig.

In the case of a single plane boundary there is only one image well, which is producing at the same rate as the actual well for a sealing boundary, or injecting at the same rate for a constant pressure boundary.

When more than one sealing boundary is present, the solution can involve a large number hundreds of image wells, depending upon the geometry of the system, and the generation of theoretical solutions can take a long time even on a modern computer. On the other hand the presence of a single constant pressure boundary will mask the subsequent effect of any sealing boundaries further from the well.

It is strictly valid only for the first ever drawdown on a well, but can in exceptional circumstances be used for analysis of a later drawdown or even a build-up. So for the MDH, a drawdown plot: Fig. John Lee John B. The first book in the SPE Textbook well testing ebook, [worldcat.

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John Lee's book has been recognized as the premier text on pressure transient analysis PTA ever since it was published 27 years ago. The fundamentals are timeless and form the basis of modern software programs for PTA. Product Details. Author: John Lee. Paperback: pages. Publisher: Society of Petroleum Engineering December