Understanding DST procedure Interpreting DST

PowerPoint Presentation Understanding DST procedure Interpreting DST pressure charts Dong Lee 30 Jul 2016 We shall discuss about The DST concept Surface Well Test Components Test Sequence of DST Dat.

We shall discuss about:

1 The DST concept

2 Surface Well Test Components

3 Test Sequence of DST

4 Data Obtain from DST

5 Interpreting DST pressure chart.

6 Well Test in Practice

Objectives are to understand:

• The DST concept

• The 3 main DST components

• The 3 main DST pressures

• The 3 main DST types

1- DST Concept

Drill-stem testing (DST) is a type of temporary completion that is used to

evaluate the formation and inspect a reservoir’s properties The measurement

of the reservoir properties by the DST can be delivered directly or indirectly

Direct measurements means that the data are recorded when the tool

assembly was down in the hole:

- Initial Reservoir Pressure (Pi)

- Flow rate measurement (Q)

- Obtaining a recovery sample of the formation fluids (PVT)

Indirect measurement or empirical measurements are those parameters that

yield from the use of equations and it includes:

- Productivity index (PI)

- Effective permeability of the formation to the fluid flow (k)

- Formation transmissibility (kh/μ)

- Skin factor (s)

- Drainage radius of the investigation test

- and detection of reservoir anomalies (such as barriers, fluid contacts,

permeability changes or layered zones)

The 3 main DST components

The 3 basic equipment for

a drill stem test consits of a

string (tubing or drillpipe), a

packer and a valve

be tested

3 The tester valve

provides a method

of controlling the well near the

reservoir

The 3 main DST pressures

Ph: Hydrostatic

pressure

Pf: Formation pressure Pc: Cushion pressure

Generally, the relationship among these pressures is:

Ph > Pf > Pc

Basic DST Tools

The Packer isolates the formation from the annulus, the two pressures (Ph and Pf) must be isolated from one another

The Tester valve

controls the formation

- shut the well downhole to minimize wellbore storage effect

- isolates annular fluid from cushion while RIH, preventing U-tubing

-provides a seal for pressure test the string

After the packer is set and sealed, the test valve can then be opened and hydrocarbons can be produced to surface

This will only occur if Pc < Ph

The 3 DST Types

• During the initial phase of the test, the wellbore fluids, and, later, the drilling fluid (mud) that has invaded the

formation in the vicinity of the wellbore flow to surface This is known as the

cleanup period Cleanup is complete when the well effluent at surface is reservoir fluid that contains no mud particles or cuttings at surface (BSW

<3%)

• Once cleanup is complete, the main flow period can be maintained for the planned duration, during which downhole pressure measurements and surface flow rates are recorded At the end of the

main flow period, the tester valve is closed Formation pressure builds up

against the valve while downhole pressure measurement continues

Basic DST Operation

• List full SWT Package

• Identify all components of SWT

equipment

• Describe the purpose of SWT

equipment

2- SWT Equipment

Well Testing Package

SWT Layout

vs.

•The flowhead controls the well pressure.

Choke Manidold & Data

Header

Choke manifold functions:

•Control the Flowrate (allow different choke sizes).

•Control the Well Head Pressure or Shut In at surface

•Ensure Critical Flow pressure fluctuations D/S choke do not affect DH Pressure & Flowrate of the well

Description: Choke Manifold

• Four or five gate valves

Separator

Separator Vessel

Description

Separation principle:

• Phase separation in a separator is based on gravity

- Gas is segregated from liquid

- Oil is segregated from water

Separation speed is a direct function of relative gravity:

Separation principle:

• Phase separation in a separator is based on

gravity - Gas is segregated from liquid

- Oil is segregated from

water

• Gravity separation only takes place when:

- Fluids to be segregated are not

soluble in each together - Fluids have different

seconds

Separation requires a few minutes

Gauge Tank/Surge Tank

Surge Tank

(Pressurized vessel)

Gauge Tank

(Non-pressurized vessel)

Principal functions of Gauge & Surge Tanks :

• Storing liquids when pressure is low

• Storing liquids when large samples are required

• Metering liquids when flowrate is low

• Measuring the Shrinkage Factor (1-shr)

• Using as second-stage separator (Surge tank only)

Burner & Boom

• The oil is disposed of through the burner located at the

extremity of the booms to reduce heat radiations towards the rig

Burner & Boom

• The oil is disposed of through the burner located at the

extremity of the booms to reduce heat radiations towards the rig

• The gas is burned separately through a gas flare located on the burner booms.

4 Clean up (till clean)

5 “First Shut-In” (optional)

6 Flowing at one or several successive flowrates

8 Final Shut-In to record pressure Build-up

(duration according to reservoir permeability)

7 Taking representative fluid samples

3 Initial Shut-In to measure or estimate initial reservoir pressure (Pi)

2 Initial Flow (communication from reservoir to casing)

1 Pressure test of the surface equipment

3 - Test Sequence of DST

P

T

Initial flow

First S.I (optional) RIH gauges

1 st flow 32/64th

2 nd flow 64/64th

Fixed choke Thru separator

Final S.I.

For pressure Build-up

Surface Sampling

Flow on 16/64 th

(BHS)

POOH

At surface 0

DST – Exploration oil well

Kill well

Test Sequence

4 – Data Obtain During a

WT

Day to day results for the Petroleum Engineer:

(Direct measurements)

1 Rough Gas composition (H2S, CO2)

2 BSW (Basic Sediment & Water)

3 WHP (Well Head Pressure)

4 WHT (Well Head Temperature)

5 Specific Gravity for OIL

6 Specific Gravity for GAS

7 OIL flowrate (Separator)

8 GAS flowrate (Separator)

9 WATER flowrate (Separator)

10 Water Salinity (if any H20?)

11 Plots P, T, Q /vs/ Time (Surface data acquisition)

12 OIL sample (non-pressurized)

13 WATER sample (non-pressurized)

14 OIL Surface PVT sample (pressurized)

15 GAS Surface PVT sample (pressurized)

16 Bottom hole sampling (single phase)

4 – Data Obtain During a

ex: S= 10 Damaged formation

S= 2 (or –1) Good (after Acid job)

3 Obtain initial or average reservoir pressure (Pi)

4 Calculate the radius of investigation (rw) or drainage area.

5 Determine presence of reservoir discontinuities or anomalies

such as boundaries, fractures, etc

5 Check reservoir limits and estimate reservoir size.

6 Evaluate well performance (Productivity) vs time from any

tendencies observed during the test.

5 - Interpreting DST

pressure charts

The initial phase of the test is observed in segment (A to B) as shown in the chart above

As the tool runs down the hole, the pressure gauges start to record an increase in the pressure This increment is due to the buildup in the hydrostatic pressure of the drilling mud column present inside the well It can

be observed that the pressure curve is not smooth because of pressure surges which occur even when the by-pass valve is open

The pressure surges are caused by the addition of connections to the drilling string Another reason for that is the existence of tight spots encountered in the hole as the well wall is not straight downwards

Sometimes pressure surges occur due to addition of water cushion or repair surface equipment All of these noises are recorded by the pressure gauges as they run down the hole

Segment A to B

Surface equipment is connected to the drill pipe during this time the

pressure stabilizes at point (B)

The pressure surges end and the initial hydrostatic pressure is

recorded relatively at the point where there is flat pressure values The driller then pick up and rotate the DST string to unlock packer then slowly lower dơn the tool string to set packer The packer seals off the area between the

interval of interest as well as the gage from the column of mud above the

packer

Once the packer is set and Nitrogen (or Sea water) is displaced in tubing

to create calculated differential pressure, the driller closes BOP rams and

apply pressure to the annulus to open the tester valve to open for few

minutes (from B to C)

The initial flow takes place from (C to D) this period lasts from 5 to 10 minutes The initial flow pressure recorded at point (C) is nearly atmospheric unless a water cushion is placed in the drill pipe This action allows the

pressurized formation fluid and drilling mud to flow into the tool and up to the surface

Segment B to D

The test valve is then closed by bleed off pressure in the annulus and the initial shut-in period takes place with a duration of 30-60 minutes from points (D to E) Surface indication of the flow are observed and the pressure builds

up reaching the Static Reservoir Pressure at point (E)

The test tool is opened again from (E to F) and the final flow period

occurs from (F to G)

The shape of the buildup will depend on the properties of the formation and the fluids

The duration of this period takes from three hours to maybe days

depending on the Wellsite Reservoir Engineer’s requirement

Segment D to F

At the end of the final flow period the test valve is again shut-in at point (G) and the final buildup period takes place from (G to H)

To remove the DST tool the driller first opens the reverse circulating

valve It is opened hydraulically by apply pressure to the annulus, with the valve open the drilling mud circulates down the annulus and up the drilling pipe to the surface The drilling fluid kills the well by keeping the formation fluids under control

Then the packer is released at point (H) either by over pull the DST string with the assistance of hydraulic jar The hydrostatic pressure of the mud

column is felt back again by the pressure recorder at point (I), then the tool will retrieve from the hole from points (I to J)

Segment F to J

6 – Well Test in Practice