Drill stem test (DST) - · PDF fileDrill stem test • A drill stem test (DST) is a...

Drill stem test (DST)

by

ALI NOORULDEEN

18-Dec-14 by Mr. ALI NOORULDEEN

Drill stem test

• A drill stem test (DST) is a temporary completion of a wellbore that

provides information on whether or not to complete the well. The zone in question is sealed off from the rest of the wellbore by packers, and the formations' pressure and fluids are measured. Data obtained from a DST include the following:

• fluid samples

• reservoir pressure (P*)

• formation properties, including permeability (k), skin (S), and radius of investigation (ri)

• productivity estimates, including flow rate (Q)

• hydrodynamic information

• This article focuses on nonflowing DSTs (NFDSTs). In a NFDST, fluid does not flow to the surface and a stabilized flow rate is not obtained (also, the well can flow to the surface but die or be shut-in before steady-state rates are achieved). Analysis of flowing DSTs is less complicated because flow rates can be measured throughout the test


http://wiki.aapg.org/Permeability

Planning

• The key to successful testing depends upon planning and teamwork between the geoscientist and the engineer. Potential pay zones should be identified before drilling commences so that the drilling program can be designed to accommodate the test. If offset data are available, the magnitude of porosity, permeability, and reservoir pressure should be identified. Knowledge of zonal mineralogy may prevent excessive damage by drilling fluids and should be used in designing the mud program. The anticipated reservoir properties are used to design the test string and test times so that the best, most useable data can be obtained.


http://wiki.aapg.org/Porosity

http://wiki.aapg.org/Drilling_fluid



Safety

• Running a DST is one of the most dangerous jobs in the oil field because the well is essentially uncontrolled during the test. All fire fighting equipment and the blowout preventers should be inspected and tested before starting a DST. Hydrogen sulfide (H2S) equipment should be on hand if anticipated conditions are sour. No test should be initiated at night or during an electrical storm. No smoking should be allowed on the drill floor or near any flow lines or surface test equipment.


Packer seats

• The best time to run a DST is just after drilling through a potential pay zone, when exposure to damaging fluids is minimal and the hole is in its best condition for a good packer seat. Packer seats are generally located in competent sandstones or carbonates above the test interval or both above and below it. The packer seat is picked by the geoscientist or mudlogger using cuttings and the rate of penetration (ROP) as guides. Soft formations, characterized by a fast ROP, usually do not make good packer seats because the packer has trouble seating or gripping the side of the borehole. This results in poor pressure seals, or in extreme cases, the packer may slide down the hole.


http://wiki.aapg.org/Rate_of_penetration

Length of test interval

• The length of the test interval should be short

so that less mud will be displaced from the rat

hole (the portion of the open hole below the

bottom packer) into the drill string.


Length of test time

• The length of flow and shut-in periods during the test are critical to obtaining good reservoir data. The dual flow, dual shut-in test is most commonly used. The initial flow period of 3-5 min removes the “supercharge” effect of mud filtrate near wellbore. The first buildup is run for 60 min to determine a valid P* (reservoir pressure). The second flow period is used to collect a fluid sample and create a pressure disturbance at a distance beyond any damaged zone. The duration of the final flow period may be anywhere between 60 and 120 min, depending upon the time available for the test and the final buildup. The final buildup is used to evaluate reservoir transmissibility, damage, and radius of investigation and should be at least as long as the final flow period. It is preferable (daylight permitting) to run the final build up three times as long as the final flow period to ensure that good pressure transient data is recorded.


Mud system

• If a drill stem test is anticipated, low fluid loss

mud will prevent excessive leakoff into the

target zone and doping the mud with nitrates

will distinguish filtrate from recovered

formation water.


Test tools

• A drill stem test string consists of packers, a

downhole shut-in valve, a safety joint, and

pressure gauges. The bottom packer and

blanked off gauge are shown as an “add on” to

a straddle test.


Packers

• Compression set packers are generally more reliable than inflatable packers because

they can withstand more differential pressure between the annulus and the drill

string. The number of packers depend upon experience and test type (conventional,

straddle, or hookwall. illustrates other types of test strings.

• Packer selection is also determined by the need for a cushion. A cushion consists of

water or gas and is run for the following reasons:

• To prevent drill string collapse during deep tests or when high mud weights are used

• To prevent excessive differential pressure across the packer(s) during the flow

periods

• To prevent high differential pressure across the sand face in unconsolidated

formations, which will result in sand flow

• To prevent corrosion of the drill string from corrosive gases such as H2S or CO2

• Cushions also provide back pressure on the formation, which inhibits flow into the

test string. If considerable damage or low permeability is expected, the cushion

should be small.


Pressure gauges

• A minimum of three (mechanical, electronic, or a combination) pressure and temperature recorders should be run on a conventional test and four on a straddle test. Selection depends on how accurate the data need to be.

• One gauge should always be run inside the drill string above the closing tool. This gauge measures the hydrostatic head of fluid produced into the drill pipe and is critical to evaluating the volumes of fluids produced during the test. It also indicates drill string leakage during the test.

• Two gauges should be run below the closing tool to measure pressure during the flow and shut-in periods. Two are needed to verify that they are reading within their calibration ranges and to provide a backup in case one fails.

• A blanked off gauge must be run on a straddle test to verify that the bottom packers were holding. In most cases of straddle test failure, it is the bottom packers that fail.


Analyzing the DST

• Interpretation

• The most important parameters in DST interpretation are the radius of investigation (ROI) and the observed wellbore storage constant (WBSC). A short ROI, combined with knowledge of drilling fluid properties (fluid loss or amount of overbalance), may indicate that the calculated permeability is indicative of only the damaged zone. Usually, a skin factor close to zero is calculated under these conditions, along with a low formation transmissibility (kh/μ). One way to “see” past this damaged zone is to rerun the drill stem test with longer flow and shut-in periods.



Perfect chart. Gauges inside above and outside below the closing tool. Pressure transient analysis done from these gauges. (A) Run in hole, gauge measuring hydrostatic pressure of mud column; (B) initial flow period; (C) initial buildup; (D) final flow period; (E) final buildup; and (F) release packer and pulling out of hole.

• If fractures are present, the measured WBSC

may be much higher than the calculated

WBSC. A high transmissibility and a negative

skin will be computed under these conditions.

A negative skin implies stimulation, which

cannot occur during normal drilling operations.

If an interval is fractured, recoveries and

calculated flow rates can be much greater than

expected future production.


http://wiki.aapg.org/Fracture

http://wiki.aapg.org/Stimulation

Calculating wellbore storage capacity

• To calculate the wellbore storage capacity (WBSC), plot log (Pws – Pwf) versus log (ts – twf) (terms defined in Table 2). Because of storage effects, the early portion of the data will have a unit slope. As these effects diminish, data points on the log-log plot fall below the unit slope line and approach the slowly curving line for no wellbore storage. The measured WBSC (WBSCmeas) is calculated using one point from the unit slope line in the following equation:


Calculating wellbore storage capacity


Variable Symbol Explanation Units

Pw s Pressure during the shut-in psi

Pwf Final flowing pressure psia

t0 Time during shut-in minutes

twf Time at last flowing pressure minutes

ts Shut in time minutes

Qlast Last flow rate stb/day

Δ t Time difference minutes

Δ P Pressure difference psi

Vrh Volume of the rathole below

the packer bbl

h Sand thickness ft

μ Fluid viscosity cp

q Producing rate stb/day

P * Reservoir pressure

determined from buildup #1 psia

Pave Average flowing pressure psia

m Slope from Horner plot psi/cycle

k Permeability md

t Flow time (in skin equation) hr

φ Porosity decimal

Ct System compressibility psi–1 rw Wellbore radius ft

kh lμ Transmissibility md-ft/cp

re Estimated drainage radius ft

Bo Formation volume factor bbl/stb

S Skin term (dimensionless)

WBSCcalc Calculated wellbore storage

constant bbl/psi

WBSCmeas Measured wellbore storage

constant bbl/psi

G1 , G2 , Gn Gradients of individual fluid

samples psi/ft

P0 ,. P1 , P2 , Pn Flowing pressures at

times t0 , t1t2 , tn psi

t0 , t1 , t2 , tn Flowing times minutes


Table 2 Nomenclature of mathematical variables

http://wiki.aapg.org/Permeability

http://wiki.aapg.org/Porosity

Calculating static reservoir pressure

• Reservoir pressure (P*) is calculated by extrapolating the pressure data (from the first buildup on a DST) on the Horner (or superposition) plot to an infinite shut-in rime (Figure 9). This pressure provides a guide for selecting the slope of the second buildup Horner plot. If the second buildup slope extrapolates to a pressure significantly less than P*, depletion might be suspected. To see true depletion, the reservoir would have to be very small. Although depletion is possible in rare cases, identifying it is usually a result of poor test design and analysis.


http://wiki.aapg.org/File:Drill-stem-testing_fig9.png




• A method for constructing the Horner plot is outlined as follows. After determining the effective producing time and producing rate, tabulate time and pressure for each buildup period. Make plots using Cartesian paper because this makes it easier to expand the plot (see Figure 9). Now plot P versus log[(t + Δt)/Δt] for buildup (the first buildup following the first flow period). Note that t in this equation is equal to the length of the initial flow period and that Δt is the time since the start of the buildup period.






• Extrapolate this curve to P* at log[(t + Δt)/Δt] = 0. P* provides the “guiding light” for determining the proper slope found using buildup #2. Now plot P versus log[(t + Δt)/Δt] for buildup #2. Note here that this t is the effective producing time calculated from one of the methods outlined earlier.

• Extrapolate the straight-line portion of the data to P*. Use a data band within the accuracy of the gauge to make sure you choose the correct slope. In other words, if the gauge is accurate within ±5 psig, then the data band should be 10 psi wide on the graph. A data band is extremely important in cases where m m using two points: (x1, y1) and (x2, y2), where


Pressure VS. time plot


• Now calculate the formation transmissibility as

follows:

• Note that k/μ can be calculated directly from

the transmissibility term if the thickness, h, is

known. Also, if a good value for μ is known,

the formation capacity, kh, can be determined.


• Calculating skin factor

• The skin factor (S) can be calculated as follows:

• If fluid properties are unavailable, skin can be calculated assuming that the log term in the previous equation is equal to 7.5. In most cases, the skin will either be positive or close to zero. A negative skin greater than –1 should be viewed with caution since the well has not been stimulated.


• Calculating radius of investigation

• The radius of investigation (ROD is important

because it helps determine whether or not the

test saw beyond wellbore damage. It is defined as

• where t is the buildup time in hours and all other

terms have been previously defined.

The ROI calculated from a DST should not be

used to identify faults or boundaries. If such items

are in question, they should be determined

through further transient testing.


• Using the pseudo-steady-state radial flow

equation, the potential of the tested interval

can be estimated as follows:

Note that Pwf in this case is the assumed

drawdown by pumping or flowing. It is not the

same flowing pressure seen on the DST. Also,

the skin factor S here may be the skin expected

after cleanup or stimulation.


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