Drill stem test (DST) is one of the most famous on-site well testing that is used to unveil critical reservoir and fluid properties such as reservoir pressure, average permeability, skin factor and well potential productivity index. It is relatively cheap on-site test that is done prior to well completion. Upon the DST results, usually, the decision of the well completion is taken.
3. Why DST
Seismic indicates the
possible existence of a
potential reservoir.
DST indicates the well
deliverability and its
worthiness for completion.
4. What is DST
• temporary completion of a wellbore that provides information on
whether or not to complete the well.
-> Done after installing the casing and before hooking-up the well.
Good DST yields:
• Fluid samples
• Reservoir pressure (P*)
• Formation properties, including permeability (k), skin (S), and radius of
investigation (ri)
• Productivity estimates, including flow rate (Q)
• -> Analysis of the DST transient pressure data can provide an
• estimate of formation properties and wellbore damage.
5. Before we start the DST
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.
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.
6. How DST
It is done in 4 stages
• Short production period (Initial Flow-IF) 5-10 minutes (A)
• Short shut-in period (Initial Build-up –IBU) 30-90 minutes (B)
• Longer flow period (Final Flow-FF) 1-5 hours (C)
• Longer shut-in period (Final Build-up-FBU) 3-10 hours (D)
Time
Pressure
A typical pressure profile observed during DST test
A B C D
7. Why is it like this
• The initial flow period removes the
“supercharge” effect of mud filtrate near
wellbore.
• The first build-up is run to determine a
valid P* (reservoir pressure) provides the
“guiding light” for determining the
proper slope found using buildup #2.
• The second flow period is used to collect
a fluid sample and create a pressure
disturbance at a distance beyond any
damaged zone
• The final build-up is used to evaluate
reservoir transmissibility, damage, and
radius of investigation (Build-up data
analysis).
9. Tools of DST
• Testing tool and packer are mounted
below the drill collars.
• Below the testing tool, a perforated
pipe (anchor pipe) is mounted.
• Inside anchor, an upper pressure
gauge is situated above perforations,
reading pressure below the testing tool.
• Below the anchor pipe, another
pressure gauge, which reads the
pressure in the annulus between the
sand face and anchor pipe.
10. Good to Know
• The wellbore is filled with mud.
• During the DST, the string is partially filled with
Cushion.
• The testing tool isolates the overlying DCs and
DPs from the mud present in the well.
• An empty string remain empty as it is
lowered.
11. Why we need Cushion fluid?
• To protect the drill string from collapse.
• To reduce the inertia of formation fluid as they enter
the pipe.
• For unconsolidated formation, pressure exerted by
cushion is 400 psi difference (or less) from formation
pressure (to prevent sand production, gravel-pack
plugging, fracture proppant production).
Cushion
Water
Diesel
Nitrogen
Natural Gas
13. Warning
• Since the DST result analysis requires the knowledge of
Pressure Build-up (PBU) analysis
• Lets first review PBU
• Then for DST data apply the PBU knowledge and equations!
15. Review of Build-up Data Analysis
• B and µ known from fluid analysis
• h is known from logging
• q is the constant flow rate of the flow period done before the shut-in
• By having m, the average reservoir permeability (K) can be easily found.
