OTC-25121-MS

A Drill Stem Well Testing Design for Extreme HP/HT Exploration Wells:
Strong design along with good operating and contingency procedures are
essential to achieve safe and efficient DST operations.
Frederic Milenkovic, Petronas Carigali; Nik Zarina, Suryana Bt Nik Khansani, Petronas Carigali

Copyright 2014, Offshore Technology Conference

This paper was prepared for presentation at the Offshore Technology Conference held in Houston, Texas, USA, 5– 8 May 2014.

This paper was selected for presentation by an OTC program committee following review of information contained in an abstract submitted by the author(s). Contents
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Abstract
Design of Extreme/Ultra (E/U) HPHT well testing, from an operator standpoint, is a difficult exercise that
involves long and meticulous preparation phases, where a large proportion of the work is devoted to
dealing with contingency procedures. The first step consists of the evaluation of the complexity of the
project since it drives the level of preparation, level of risks, support /expertise requirements and their
financial impacts. The Value Of Information must be accurately justified since HPHT well testing
involves tremendous costs. The second step is to understand what it takes to deliver an E/U-HPHT in a
safe and efficient manner, meeting well testing objectives. Basis of design and procedures are developed
without overlooking the importance of tubing stress analysis, design reviews, quality insurance, and
laboratory tests (qualification or verification). The proper well construction and its integrity is of
paramount importance in the success of well testing operations since it provides the operating envelope
DST tools are relying on. This envelope will be highly stressed during all DST load cases and therefore
all DST components installed are designed to accommodate these stresses safely. The uncertainties of
actual Pore Pressure, Temperature (down-hole and surface) and reservoir fluids make the exercise even
more complicated, therefore, implying a great deal of preparations and contingencies need to be in place.
The importance of selecting the right annulus fluid increases the chance of a successful operation and thus
under balance versus over balance testing philosophy must be thoroughly evaluated to resolve the
dilemma of well control versus DST tools operability. All this steps must be taken after a thorough review
of what the current technology can offer along with the understanding of its limitation. Over the last few
years, services companies noticeably pushed to develop extreme tools in order to provide viable technical
solution to complex Ultra HP-HT well testing. Nevertheless, recovering the DST string is known as being
one of the upmost challenge in HPHT well testing, meaning the design of the production string (including
a tubing free strategy) must be planned well in advanced. No string back to surface means no down-hole
data & samples, therefore missed objectives and waste of money.
This paper describes a design approach and preparation for an EU-HPHT well testing on an exploration
well being the first to be implemented by PCSB.
2 OTC-25121-MS

Introduction
Well testing activities usually happen at the end of the drilling phases of a well after targeted reservoir(s)
has been logged and confirmed to be good candidates for dynamic well testing. The decision to test the
well or not depends on several factors, notably the results of the logging surveys and equally is the value
well testing results will bring to the operator (Value Of Information). No matter if the well is tested or not,
the preparation of the Well Testing activities involves a great deal of engineering and high upfront cost
to secure the equipment and services. This is particularly true in challenging environments such as Deep
and Ultra Deep Water, Normal-Extreme-or Ultra HP-HT, Highly Corrosive reservoir fluids, Artic or urban
environment, etc. . . Obviously, when the activities occur under all said conditions the project becomes
even more complex. The following matrix recalls most of the important criteria to bear in mind when
evaluating the complexity of a well testing project. It gives indication of the level of risks and costs an
operator is willing to take. Notwhistanding the high cost involved in complex well testing projects, many
factors must be taken into account, such as long preparation time (sometimes more than 2 years), high
technical risks leading to the development of mitigations and contingencies, the requirement for the best
qualified technologies run by premium service providers. In all the cycles of the project, the expertise of
the service company is crucial (knowledge, methodology, design & procedures, controls,. . .) where a key
contributing success factor resides in people.
The present document aim to provide some insight of the methodology employed in the design of an
Extreme HPHT well testing operations. It refers to the Well Kinabalu – X (KN-X) in Malaysia, offshore
Sabah in the East Baram Delta province. Reservoir depths are about 17,000 Feet from surface, Reservoir
pressures ranging from 14,000 to 16,000 Psi with an associated temperature of 280 to 310 DegF. These
parameters classify the well testing operation into the Extreme HPHT category.
OTC-25121-MS 3

Value of Information
At the beginning of field development, many questions require an answer regarding the reservoir
uncertainty and associated risk, before the final proposition of field development plan is released.
Mitigation of risks and uncertainties can be through additional acquisition of information. Information has
value within a project, involving significant costs to invest to get value of information. Very often, it has
to be decided if additional information should be gathered before an investment decision is taken. In
Kinabalu field, the additional information from testing the well KN-X is required, mainly to develop the
third phase of the HPHT project. It is not common to accept the fact information does have a cost and it
does have a value. Costs are generally known before gathering information. It is less intuitive to assign
value to the information before gathering it.
In general, the value of gathering additional information depends on three factors:
1. The degree of uncertainty
2. The representativeness of the additional information
3. The decision flexibility
In KN-X Exploration well, more data is required to understand the behavior of the deeper reservoir
further. It is critical to determine production data in Extreme HPHT environment. There is limited
information at this moment to develop the deeper field and determine the concept of the production
platform, the number of wells, the completion design, the production forecast, etc. It is crucial to perform
well testing in major reservoirs. The objectives of testing the well are to determine well deliverability,
flow performance, to confirm fluid, to assess sand production and estimate reservoir boundary. Since DST
Extreme HPHT well testing involves high expenditures, it is worthwhile to spend more on time to improve
data acquisition and evaluating the results.
The application also include long-term test to determine aquifer support and reservoir boundaries. An
example of the long test requirement is to determine whether there is aquifer support in the structure and
the fault boundary. If the long-term test shows no aquifer support, the tested well will be produced as long
as reasonable to minimize the cost. If the long-term test proves aquifer support, there is a need to evaluate
the reservoir further. Sometime, the long-term test is required to understand how big the structure is and
understand the reservoir boundaries.
Value Of Information is important to understand the impact and cost. To make prudent decision, both
factors need to be analyzed and assessed carefully. VOI determine the worthiness of acquiring extra info
to help decision making. From decision analysis perspective, acquiring extra information is only useful if
it has significant probability of changing the decision maker’s current preferred strategy. The penalty of
acquiring more info is usually valued as the cost of that extra information, and sometime the delay
incurred in waiting for the information.
VOI techniques are based on analyzing the revised estimated of model inputs that come with extra data,
together with cost of acquiring the extra data and a decision rule that can be converted into a mathematical
formula to analyze whether the decision would alter.
The usual starting point of VOI analysis is to consider answering the questions “What would be the
benefit?”, “What are the chances of success in Extreme HPHT DST?” If the cost is less than the value,
it is recommended to pursue further. The value of information from KN-X well testing is higher than the
cost of well testing itself. That is the reason to proceed with DST to acquire new information in order to
develop third phase of HPHT development. In VOI analysis, the benefit of the info is close to cost, the
final value can be considered high. If the well test is cancelled, there will be no basis for developing gas
in “Lower Ultra-Deep” reservoirs.
It is often assumed the data acquisition program is carried out successfully, as planned, therefore giving
the subsurface team the insight of the reservoir characterization from the acquired data. Unfortunately, due
to un-planned operational issues, part of all required information is not available. The incomplete data
4 OTC-25121-MS

collection and well test results have the potential to erode the value of data acquisition. Realizing how
much value is lost due to incomplete or imperfect data acquisition suggests that it might be worthwhile
to spend more on sophisticated data acquisition, or spend more to improve existing data acquisition
methods. In this way, the VOI analysis helps to find ways of optimizing value for money. Sometimes,
when a DST is not successful, the available methods are correlations and assumptions to estimate the best
information. However, the results are still uncertain.
VOI magnitude depends on economic evaluation. In this case, we have evaluated based on EMV
results. It shows positive EMV results to proceed with HPHT well testing although this is very expensive
venture. However, it is justified due to value of the information.

Well Testing Basis of Design

A complex well testing project starts with a basis of design. It is typically a comprehensive document
listing well testing objectives and the methodology the operator would apply to achieve them. This
document needs various input from several department within the operator organization:
Statement of Requirements:
This document is commonly referred as SOR, a terminology used by many operators. It is written and
endorsed to summarize important geological information about the well, and what the drivers of drilling
the well are. The SOR serves as a reference document for well trajectory plan, pore pressures prediction,
data acquisition strategy, and obviously well testing objectives. The well test engineer shall ensure the
well testing design matches all pertinent requirements. Any issues or showstoppers would have to be
discussed well in advance and their consequences well understood by the project team.
Well Design and Construction:
This is a well proposal containing a wealth of information: Well summary, Geodesic description, Well
Objectives, Field description, Geophysical and Geological description, Well logging program, Mud
logging requirements, drilling risks and uncertainties, well cost and engineering, well testing nodal
analysis, etc.. It also constitutes a valuable input in the design of well testing operations.
Drilling program or abstract
The drilling program or abstract gives the well testing engineer valuable information about the rig
capabilities, the BOP engineering details, the well construction and integrity, etc. . .Sometimes, especially
in HPHT environment; it is associated to a Casing Basis of Design.
The well testing Basis of Design drives the philosophy of the operations. It is a kind of feasibility study
where the list of technical challenges are discussed and technical solutions are proposed. Often, several
solutions exist to achieve the same goals; the test engineer therefore builds cases explaining advantages,
disadvantage of each of them, and concludes with the rationales of the preferred option. Due to numerous
uncertainties in drilling wildcat wells, decision trees are also developed to provide guidance covering
different scenarios. The aim is to be prepared well in advance to address all cases, thus avoiding last
minutes major changes. The basis of design has to be endorsed by the stakeholders of the project, in
particular the subsurface team & the drilling team. This is generally done during an internal peer review.
On complex project, a third party verification could be useful providing the third party company is
sufficiently knowledgeable. The typical content of a Basis of Design for Extreme HP/HT or complex
applications is:
y Project Introduction, well & reservoir parameters
y Well Construction, selection of candidate intervals
y DST Well Test Sequence
y Schedule of operations and duration of DST
y Well Integrity Specific to Well Testing
y Tubing Stress Analysis, selection of Packer and annulus fluids
OTC-25121-MS 5

y Perforation Strategy
y Down hole Test Tools
y Sand Monitoring and Control
y Annulus pressure management
y Well Intervention and Free tubing Strategy
y Equipment Validation and qualification
y Contingencies
y Cost of operations
The following chapters are dealing with the most critical steps of the Well Testing Design.
A- Well Construction and selection of candidate intervals
The well construction is managed by the drilling team based on the input from the subsurface group. Well
test engineers are rarely involved in this exercise. The involvement of the well test engineer shall start as
early as possible for several reasons:
● There is a limited choice of production or DST packers designed to address Extreme to Ultra
HPHT well testing challenges, whether because of the casing size and grade, or whether because
of a lack of certified ISO 14310 (API11D1) V0 product. Moreover, DST packer envelope is
usually not available to the operator’s well test engineer. It is quite impractical (cost and lead-time)
to design and build a packer for a particular DST operations so every effort shall be taken to build
the well based on existing qualified packers.
● The production liner is often undersized to accommodate large perforation strings, especially when
guns are lowered down through a permanent seal bore packer. For instance, a 7” Permanent seal
bore packer can accommodate a 2 7/8” perforation string whereas a 7 5/8” Permanent seal bore
packer is suitable for 3 ½” perforation string. The difference between the two perforation solutions
is an increase of the perforation length and entrance hole in excess of 30% for the latter.
● The well test engineer advises at the early stage if the planned DST is feasible based on the well
and reservoir constraints, type of fluid and down-hole tools functions and rating.
● In case of multi-layer reservoirs, the selection of the candidates requires the input of the well test
engineer about zonal abandon, sump length requirements, and distance from top perforation to
test/production packer. Some reservoir cannot be tested standalone when too close from each
other, whereas some cannot be tested commingled due to pressure regime differences or other
factors.
B- Well Integrity specific to DST
Similarly to the well construction, the well integrity insurance is managed by the drilling team. The well
test engineer shall not overlook this critical point since the exploration well is built to accommodate DST
tools. A particular attention shall be paid on:
● The well envelope (Annulus A) has been pressure tested. The pressure test value shall be
equivalent the maximum expected gas to surface pressure (including a safety margin) with the
packer fluid media in the annulus. This case will cover a tubing leak to annulus, which is assumed
the worst case.
● An Annulus Pressure Build up survey has been done in order to confirm the maximum allowable
flow rate and duration the well envelope can endure. This is particularly pertinent when B and C
annulus are plugged at surface.
● The Plug Back Total Depth cement barrier and liner top has been inflow tested. Two main scenario
can be considered:
● In case of DST with underbalanced fluid in the annulus, the inflow test shall cover the pressure
differential between the reservoir virgin pressure and the hydrostatic pressure of the packer fluid.
6 OTC-25121-MS

The reservoir pressure is not necessarily the virgin pressure of the reservoir to test. It could also
be a higher pressure from another zone (lower or even upper) when suspicion of pressure
channeling behind casing exists.
● In case of DST with an overbalance fluid in the annulus, the inflow test shall cover the pressure
differential between the reservoir pressures (or over balanced hydrostatic pressure, whichever is
greatest) and the flowing pressure at maximum expected drawdown, including a reasonable safety
margin.
● Some contingencies are already in place to deal with any potential pressure integrity failure at the
bottom isolation plug or the liner top. Typical remedial are bridge plugs (or plugged production
packer) and liner hanger tie back packer. When remedial plan has been exercised, the sequence of
inflow test shall take place again. Note that it is always best to carry out to dedicated inflow test
of the bottom plug and liner top separately, the advantage is to ease the diagnostic in case of well
integrity failure.
● Even though the BOP is not part of the well integrity itself, some precaution must be taken when
testing E/U HPHT wells. Firstly, it is highly recommended to change BOP rams just before DST
operations commence (even in subsea operations), in particular when the expected surface
temperature is high. Secondly, two sets of rams shall be designed to close around the surface or
subsea-landing string, with at least one fixed rams set. Thirdly, the shear rams shall be suitable to
shear a landing string tubing or shear sub. Calculation of shearing capacity must be done; shear test
would be more beneficial. Fourthly, the BOP kill line shall not be used to pump fluid into the well
during DST operations, it is better to use the choke line and keep the kill line in good health,
especially if abrasive muds are used as packer fluid.
● Production tree is preferred when the maximum expected surface pressure exceed 85% of the 15
Kpsi surface test tree rating and when surface temperature is equal or above the BOP temperature
rating. This is even more pertinent when reservoir fluids are highly corrosives. A flanged flow line
shall be considered as the best choice over flanged temporary piping.
● When the DST operations are carried out in an over balanced packer fluid, a subsea riser margin
shall be implemented to keep the well over balanced when the marine riser is disconnected.

C- Tubing Stress Analysis

Numerous articles have been written to highlight the importance of Tubing Stress Analysis for standard
or complex operations. Even though the analysis is more dedicated to completion design, it helps to design
well testing operations thanks to the following outcome:
● Temperature rating of surface equipment
● Tubing Selection
● Packer fluid Selection
● Packer Specification (pressure rating, forces)
● Tubing movement
● DST tools Pressure rating
● Over-pull margin after DST

Surface temperature predictions are one of the most valuable information. Integrated Production
Modelling Software are also used to crosscheck the results of the Tubing Stress Analysis surface
temperature prediction. The tubing Stress analysis requires a thorough assessment of the input and some
margin to cover extreme cases or unexpected cases:
The design inputs are accurate and feature enough safety margin to cover unexpected cases. For
instance, an expected reservoir temperature of 350 DegF will become 380 DegF as an input. The same
philosophy applies to other key input parameters such as the well deviation for instance. Indeed, the
OTC-25121-MS 7

test engineer shall anticipate a higher deviation than what is actually planned. Another way to look at
it is to perform the analysis using base case input and then perform a sensitivity analysis where the
inputs incorporate a safety margin.
The selection of the highest reservoir pressure in case of multi-layer reservoir as the most dimensioning
case. Indeed, it is often assumed the well will be stressed by the targeted reservoir pressure,
temperature, and fluids. This is not necessarily true as there is sometimes a fluid migration from
higher-pressure reservoir. This can potentially make surface pressure higher than the rating of surface
equipment.
Conversely, the low-pressure range of the prognosis shall be taken into consideration as well. Indeed,
it may happen that reservoir pressures are much lower than expected, thus justifying the use of a 15
Kpsi equipment instead of 20 Kpsi. The benefit is the considerable time saving in rigging up lighter
equipment compare to the installation of a X-mas tree.
A good inventory of all DST load cases. It is important to evaluate what would be the stress on tubular
and Packers based on the most stringent cases. Those cases are driven by the DST tools settings but
also potential failures such as a tubing leak at the wellhead that could collapse the tubing above packer
or burst a casing or liner. The most common load cases are described here after (DST with TCP string
lowered through a permanent seal bore packer):
● Initial Conditions: [ Well Static – Not Perforated ] The DST completion has been ran in the well
and in position to proceed further. On surface, the surface test tree or Christmas tree is set in place.
The annulus and tubing are filled with the packer fluid (i.e. Sea Water). The completion is now
ready for final pressure testing.
● Tubing Pressure test: [ Well Static – Not Perforated ]The conditions are similar to the previous
cases, with the exception that a pressure is applied in the tubing to test the integrity of the tubing
up to the Tubing Test Valve (tubing plugged above DST BHA). The pressure test value is higher
than the Maximum Shut-In Well Head Pressure (MSIWHP) ⫹ 5% (or 500 Psi) of bullhead margin
(BHM). The pressure test value shall be determined to avoid over pressurizing the system more
than necessary. For instance, if the MSIWHP ⫹BHM equals to 13,500 Psi, a pressure test value
of 13,800 sounds reasonable.
● Test Packer from below: [ Well Static – Not Perforated ] This sequence happen after the
completion integrity is confirmed. Firstly, the Tubing Test Valve is cycled open by applying
pressure in the annulus (typically from 500 to1000 Psi), allowing communication from surface to
bottom. Secondly, pressure is applied from surface in the tubing in order to carry out a positive
pressure test below the packer. This sequence is designed to ensure the packer will hold the
differential pressure from bottom to top. Note that below the packer, the TCP guns are in place
with a hydraulic firing head that could trigger in case the applied pressure reaches the operating
window of the firing head. To overcome this problem, an intelligent TCP firing head (pressure
pulses or telemetry or mechanically indexed) is adequate. Otherwise, a slick line firing head could
also be used in some circumstances. The pressure test value of the packer shall be higher than the
maximum expected differential pressure at the packer from bottom to top.
● Activate TCP firing head: [ Well Static – Not Perforated ]If an intelligent slick line TCP firing
head is used, there is no special load case to simulate. If the packer has been tested already without
the DST string in the hole (i.e a permanent seal bore packer tested with a dedicated run on drill
pipe) then it is wise to simulate the case where an hydraulic time delayed firing head is activated.
Prior to activate the firing head, the cushion fluid is spotted in the tubing while displacing the
annulus fluid thanks to the DST multi-cycle reversing valve. The tester valve is kept open (fail safe
position) by applying a pressure in the annulus of approximately 1,500 Psi. To activate the
hydraulic firing head, pressure is applied in the tubing and acts on firing head piston, shearing pins
8 OTC-25121-MS

and triggers the guns after a pre-determined delay time. The apply pressure can be high, in the
range of 6,000 to 12,000 Psi.
● Flow the well at Low rate : [ Well Flowing – Perforated ]This case covers the scenario when
the well is flowing at low rate after the interval has been perforated. Because of dynamic well
conditions, the temperature at the well bore and tubing increase thus creating tubing movements
and increasing pressure in annulus. The completion is now filled with reservoir fluids, whereas the
annulus is monitored to keep pressure in the range of 1,200 to 2,000 Psi typically. This case is less
stringent than the next one when the flow is at maximum flow rate.
● Flow the well at Maximum rate: [Well Flowing – Perforated]This case is similar to the
previous case but the well is now flowing at the maximum rate. This mean the surface temperature
is the highest, whereas the tubing head pressure is the lowest. Temperature and pressure in the
annulus is building up fast and requires a close monitoring. The tubing shall see a greater
expansion (downward movement of the packer seal assembly). It is during this sequence the
maximum surface temperature is recorded during the entire DST cycle. Surface temperature is
dependent on the duration of the flow period. In order to determine the most stringent case, the test
engineer can select the option of steady flow instead of defining a fixed flow duration. A good
practice as well is to enter some liquid rates (oil or condensate, water) even on a dry gas scenario.
Indeed, the surface temperature would be higher than the base case and allows to confirm is the
surface set up could handle hot liquids.
● Tubing Evacuation: [Well Flowing – Perforated]This case simulates a condition where a
blockage at the wellbore occurs (typically plugged perforations or sand screens), preventing
communication between the tubing and the sand face. This rare case perhaps never happened
during DST operations. Indeed, contrary to Production Completion operations, DST operations are
manned continuously, meaning that any sign of tubing head pressure drop are addressed rapidly,
well before tubing pressure at packer reach a critical low value. Nevertheless, it is wise to run this
case in the analysis where the annulus is pressurized to typically 1,500 Psi at surface to keep the
tester valve opened. This case shows a high differential pressure from the annulus on top of packer
(Annulus hydrostatic Pressure ⫹ surface applied pressure) versus the lowest tubing pressure. The
differential pressure is obviously much higher when the well is tested with a high-density packer
fluid compare to fresh or seawater. In this case, it is frequent to see the load case exceeding the
packer envelope boundary
● Tubing leak: [Well Flowing – Perforated]This case simulates a condition where the well is
flowing at minimal reservoir drawdown pressure and 1500 psi in the annulus to keep the tester
valve open. In case of tubing leak just below the tubing hanger, the annulus pressure will increase
and equals the tubing head pressure. The consequences are the activation of the DST tools (disc
bursting sequentially) and potentially burst the weaker casing/liner in the well envelope. When an
emergency pump through safety valve is used in the string, it would activate and isolate the
reservoir pressure from the tubing, unless the tubing leak is located below the same safety valve.
● Build up leak: [Well Static – Perforated]This case is similar to the tubing leak during a buildup
period where the well is shut at surface. The main difference is coming from a more stringent gas
gradient (0.1 Psi/Ft) instead of a calculated gradient from the fluid composition. The effect is a
slightly higher pressure applied from tubing to annulus, therefore more forces acting on the Packer.
This case is more stringent than the previous “tubing leak case” and shall be used to confirm the
well envelope is robust enough.
● Activate Emergency shut in: [Well Flowing – Perforated]This case simulates a situation where
the well has to be shut down-hole by applying surface pressure in the annulus to close a down-hole
emergency safety valve. This valve is not fail-safe and requires human intervention to be cycled
in closed position. It is a contingency device and therefore the pressure setting is well above setting
OTC-25121-MS 9

of the last DST tool used in normal circumstances. In this situation, the well is flowing at the
highest rate (with the maximum drawdown at the reservoir level) with an applied pressure in the
annulus ranging from 5,000 to 8,000 Psi typically. This creates the largest differential pressure at
the packer/tubing level when packer fluid overbalances reservoir pressure.
● Shear Single Shot Reversing valve: [Well Static– Perforated ]This case simulates a situation
where the well is static but not killed yet. High pressure is applied in the annulus (above the
pressure setting of the emergency safety valve, if any) to shear a rupture disc that will activate the
single shot hydrostatic reversing valve, allowing communication between the annulus and tubing.
This operation is conducted in contingency in case the multi-cycle reversing valve fails to cycle
and the Tester valve remains stuck in closed position. This case sees the highest pressure in the
annulus throughout the entire DST sequence
● Well Killing Start: [Well Static – Perforated]This case simulates a situation where the well is
static (surface shut in) and surface pressure is applied in the tubing to pump reservoir fluids back
to the formation and kill the well (Top Kill Bull Heading). Surface pressure is calculated by adding
500 psi on top of the Maximum Shut-In Well Head Pressure. It assumes the tubing content cannot
be reversed because the DST Tester valve fails to close for instance. While pumping (kill fluid)
is progressing, the surface tubing pressure is decreasing whereas the pumping rate increases over
the time. This case shall not occur providing the DST tester valve and reverse circulation valve
work properly. In this case, the well killing procedure would be less stringent (reverse circulation
⫹ bullhead volume below tester valve).
● Well Killing End: [Well Static– Perforated but Killed ]This case simulates a situation that is a
continuation of the previous load case “Well Killing Start”. The main difference is a much lower
surface tubing pressure and an increase in the pumping rate.
● Over-pull Margin: [Well Static– Perforated but Killed]This case simulates a situation where
the well is static and killed with the hydrostatic pressure at bottom greater than reservoir pressure.
On top of the packer, annulus pressure and tubing pressure are equalized through the open port of
the single shot reverse circulating valve. The case is built to determine in advance, what would be
the safe over-pull margin in case the string would be stuck at the level of the packer or below. The
over-pull margin will be determined by the weakest element of the tubing string. Indeed, DST
strings are often made of a combination of different tubing size and weight, especially in Deep
Water application where the subsea landing string is often larger than the production string.
There are additional load cases that could be evaluated such as a well stimulation, an injectivity test,
tubing running in the hole, etc. The output of the Tubing Stress Analysis gives more than the forces and
pressure acting on the tubing. It helps to determine the requirement of the production packer (Forces,
differential pressure, floating seal assembly stroke), fine-tune the density requirement of the packer fluid
when load cases reach the limits of the envelopes, and calculate the over pull margin, etc. . .
The Production/Test Packer
Forces acting on packer and associated differential pressures are calculated in the tubing stress analysis.
The tubing length changes calculation would also determine the requirement of the safe length of the
floating seal assembly in case a seal bore packer is used. Similarly to the production completion designs,
the DST design shall give the assurance the packer is suitable to address all load cases. For that purpose,
the Packer working envelope shall be supplied by the service company in order to plot all load cases as
depicted in the following illustrations.
In this example, the green envelope comes from a permanent seal bore packer, whereas the dotted black
envelope comes from a retrievable seal bore packer. All expected DST load cases are plotted using the
same axis. This design employs seawater as the packer fluid (underbalanced fluid); the reservoir pressure
is around 16,000 Psi with a formation temperature at 330 DegF. A quick look tells the permanent seal bore
10 OTC-25121-MS
OTC-25121-MS 11

Advantages
Permanent Production Seal Bore Packer Retrievable Production Seal bore Packer Retrievable DST Tubing wall Packer

Highest anchoring strength mechanism (highest Easy retrieval, beneficial for zone Easy retrieval, beneficial for zone
tension, compression rating) abandonment abandonment
Highest achievable differential pressure rating Multi use after redress Multi use after redress
Largest ID (therefore largest TCP OD when Field Proven Technology Field proven technology
lowered through)
Do not require set on weight and slips joints V0 rating can be achieved Can feature a by-pass below sealing
elements
Cheapest option Can feature a by-pass below sealing Can accommodate larger TCP guns
elements connected to Packer body
Field Proven Technology, best choice for HPHT Can accommodate larger TCP guns Ran with the DST string in a single run
applications connected to Packer body
V0 rating can be achieved Ran with the DST string in a single run

Disadvantages
Permanent Production Seal Bore Packer Retrievable Production Seal bore Packer Retrievable DST Tubing wall Packer

Requires milling to be pulled out thus higher More expensive than permanent packer Expensive to rent (equipment and
operating cost personnel)
Risky operation in case TCP guns are connected Smaller ID, thus reducing TCP OD if Cannot be pressure tested from the top
below packer body (misfire, milling and lowered through (annulus with DST tools)
retrieval)
Seal assembly could disengage if tubing Lower tension and compression rating Cannot be set at different depth otherwise
movement are larger than expected TCP below are off depth
Seals can “bond” to the seal bore over long time Reduced operating envelope compare to Requires safety joints, slips joins, heavy
at higher temperatures, risk of stuck string permanent packer weight collars and hydraulic jar
Debris on top of packer can stick assembly Can unset prematurely Limited casing size and range, not
addressing HP applications
Difficult abandon of tested interval if packer is Seal assembly could disengage if tubing Operating envelope usually not disclosed
not retrieved movement are bigger than expected
Seals can “bond” to the seal bore over long Not adequate for DST on floater rig
time at higher temperatures operations
Debris on top of packer can stick assembly Reduced operating envelope compare to
permanent packer
Usually not V0 rated (V3 at best)

packer is the best fit since all the load cases point are within the envelope, especially worst cases like
tubing evacuation or tubing leak.
When the packer fluid is changed to an Oil Base Mud at 18 PPG, the well overbalances reservoir
pressures. In this case, the packer envelopes remain obviously the same but the load cases are having a
different distribution within the envelope, with few points going beyond the upper right borders. Even if
base cases are within the envelope, worst cases (tubing leak and tubing evacuation) are largely out. Heavy
mudat 18 PPG is not appropriate for the tubing and perhaps not for the well envelope too.
The assessment of the suitable type of packer looks easy but the pros and cons of each solutions shall
be thoroughly evaluated. Indeed, three type of packer are commonly used in DST (Seal bore Permanent,
Seal bore Retrievable and Tubing Wall Retrievable), they all bring their own advantages, but often their
weaknesses disqualify them:
Nowadays, most of the N/E/U HPHT DST operations are carried out with a permanent seal bore
packer, thanks to the numerous advantage it brings. Nevertheless, over the past few years a new concept
of packer has been brought to the market and is matured enough to be selected as a viable option. Indeed,
this packer solution is similar to a completion retrievable seal bore packer with adequate customization
to address DST applications. It is run with the entire DST string and TCP guns connected below the packer
assembly in a single run. The packer is set in place and then pressure tested from below, providing the
12 OTC-25121-MS

pressure do not exceed the trigger limit of the hydraulic TCP firing head (in this case it make sense to use
an intelligent or pressure indexed firing head instead). The packer is set at depth by applying pressure in
annulus, which burst a predetermined rupture disc and enable communication with the hydraulic setting
mechanism. This is particularly wise in subsea application since the packer does not required any rotation
and down weight to be set. The tubing movements during the course of the DST are compensated with
a floating assembly that remains within the seal bore extension at all time. The packer also features a
Below Packer Circulating Valve (BPCV) that helps to get rid of the trapped gas below the sealing element
when killing and reversing the well content out. Finally, a straight pull of approximately 20 Klbs suffice
to release the packer.
There are few guidance to follow with regards to the optimum packer setting depth. Firstly, the distance
between the perforation top shot and packer should be minimized to ease bull-heading hydrocarbons back
to the formation once the test is over. Secondly, on the opposite, the packer setting depth shall be suitable
to minimized shocks induced by the perforation, as further explained in the perforation strategy chapter.
Thirdly, the depth shall be selected based on the cement sheath evaluation at a place the casing is well
cemented. There is a safe distance to respect where the packer is ideally placed at minimum 30 meters
above the perforation top shot and minimum 30 meters below the liner top.
E- Packer Fluid
The selection of the packer fluid is not so obvious. Indeed, the packer fluid acts as a buffer between the
packer and the wellhead, designed to accomplish several tasks:
● Keep hydrostatic pressure above packer to counter negative forces
● Reduce differential pressure across tubing wall
● Transmit applied pressure from surface to DST tools
● Reduce heat transfer from Tubing to Annulus and from reservoir to surface
● Prevent corrosion in annulus

In DST, packer fluids are liquid based, mainly Oil Based Mud, Water Based Mud (dense Brine), Brine,
Seawater or fresh water. They all provide a solution to accomplish the above-mentioned tasks, with some
degrees of efficiency ranging from poor to very good. The first three are usually selected when there is
a requirement of overbalanced fluid, whereas seawater and fresh water tends to be selected as an
underbalanced fluid to maintain the operability of the DST tools.
Oil and Water based mud reduce significantly the efficiency of the DST string for several reasons.
Firstly, the transmission of the pressure to the DST tool is very poor, exacerbated when the well is deep
and/or deviated and when the clearance between the tubing body (and connection) and the annulus is tight.
Secondly, solids tend to come off the solution and accumulate on top of the packer. These phenomena
prevent the string to come free or even tend to block the ports (hydraulic ports or circulation ports) of the
DST tools. Thirdly, the fluid has a poor cool off power leading to a higher surface temperature compare
to brine or water. Some mitigations are designed to reduce the negative impact of the first two points, like
the pressure transmissibility test and the mud sagging test. The pressure transmissibility test is carried out
in situ where a string is lowered in the hole (dummy run or DST string with real time data transmission)
and pressure is applied at surface to simulate the pressure cycle in the annulus during a DST operation.
Down-hole gauges record pressure at the DST string and the offset pressure is calculated by the difference
of surface applied pressure minus the difference between the hydrostatic and incremented pressure at the
DST tool. The difference can easily go beyond 1000 psi when the well is deep, deviated and the packer
fluid is very heavy. This method is a recognized practice but the results are very dependent on the
down-hole temperature when the test is carried out. This problem is partially overcome when DST tools
operates with command sent on surface via wireless telemetry, but re-occur if the primary method of
command fails (when the rupture disc mode override the wireless telemetry mode). The mud sagging test
is done in a laboratory and last the expected duration of the test, with pressure and temperature cycles.
OTC-25121-MS 13

Even if the test prove the mud rheology is correct, it does not guarantee solids will not drop off during
the DST operations.
For the above two reasons, it is best to stay away from oil or water based mud, even though keeping
the well under balance is the major advantage. Brine is a good alternative since it provides a solution that
satisfies well control requirement (over balance fluids) and DST operability. It is suitable for reservoir
with moderate pore pressure and/or moderate reservoir burial depth.
Fresh water and seawater are sweet media that in most of the cases, keep the well under balanced. Their
main advantage is they keep an optimum pressure transmissibility to down hole test tools and a low the
hydrostatic pressure that prevent the casing to burst or tubing to collapse in case of a tubing leak at surface.
They both tend to increase the success rate of the DST operations.
No matter which packer fluid is selected for the operation, a thorough assessment has to be made to
weigh the pros and cons of each solution. There is a significant cost implication in each of the solution,
along with some practical considerations to take into account such as the conditioning, the pit manage-
ment, hydrates prevention, filtration, toxicity, disposal, etc. . .
F- Perforation strategy
In N/E/U HPHT DST, the perforation strategy is driven by the selection of the packer, rarely by the
perforation objectives. Drill Stem Testing does not require the maximum penetration length contrary to
production wells, but still, in tight formations, the longer the better. Since DST tools are standardized with
an internal diameter of 2.25” (slim bore and large bore DST are not discussed here), it is not practical to
conveyed perforating gun on wire line, slick line, or coil tubing to the targeted interval. Indeed, the
restriction in internal diameter implies the used of slim guns, typically sized below 2 inches of outer
diameter. This perforation assembly would not give adequate perforation length and entrance hole,
especially when perforated heavy wall casing of 7 inches ID or above. Moreover, some operators have a
clear policy to avoid running cable below the DST tester valve and/or during deep-water operations.
Therefore, the most appropriate conveyance mode is with the Tubing (or drill pipe under special
circumstances). The most common TCP conveyance is classified under 5solutions, their advantages and
disadvantages are described further:
Run TCP on Drill Pipe, shoot and Pull. Then Run DST and test.
Run TCP on Drill Pipe, anchor TCP in casing, run DST, shoot and Test
Run Permanent Seal Bore Packer on Drill Pipe with TCP connected underneath, run DST, shoot and
Test
Run DST Retrievable Seal Bore Packer on Drill Pipe with TCP connected underneath, run DST, shoot
and Test
Run Permanent Seal Bore Packer on Drill Pipe, Run TCP and DST on tubing, sting through, shoot and
Test
An important criterion of selection is obviously the rating (Pressure, temperature) of the TCP string.
In high temperature reservoir, the exposure time of the TCP string shall be minimized as much as
reasonably applicable. In this case, a shoot and pull solution would be the preferred option providing a

Option 1—Run TCP on Drill Pipe, shoot and Pull

Advantages Disadvantages

● Large guns size ● Perforating over balance only

● Easy operations ● Perforation tunnel invaded by gun debris
● No need for long rat hole ● Rig time (2 to 3 runs in total)
● Shot performance checked at surface (post-Fire) ● Well Control (trip in/out with open perforations)
● Reduced risk of stuck guns ● Difficulty to switch the annulus to underbalance fluids
● Easy correlation ● Unable to test the DST packer from below
● Shortest Explosive time exposure ● Difficult well flow start up
14 OTC-25121-MS

Option 2—Run TCP on Drill Pipe, anchor TCP in casing, run DST, shoot and Test
Advantages Disadvantages

● Large guns size ● Risky operation

● Under-balance perforations feasible ● Highest rig time if misfire (packer milling, then guns retrieval)
● Guns not connected neither to DST string or packer ● Rat hole requirement (if dropping required)
● Easy correlation ● 3 Runs (TCP, Packer, then DST string)
● Gun drop achievable ● Highest time exposure of Explosives at high temperature
● Costly solution

Option 3—Run Permanent Seal Bore Packer on Drill Pipe with TCP connected underneath, run DST, shoot and Test
Advantages Disadvantages

● Large guns size ● Gun space out issues if packer cannot be set at required depth
● Under-balance perforations feasible ● Large Rat hole required to drop the guns
● Guns not connected to DST string ● Long exposure of Explosives at high temperature
● Easy correlation ● TCP miss run difficult to manage (packer milling with guns
● Gun drop achievable connected underneath)
● 2 Runs (Packer ⫹ TCP, then DST string)

Option 4 —Run DST Retrievable Seal Bore Packer on Drill Pipe with TCP connected underneath, run DST, shoot and Test
Advantages Disadvantages

● Large guns size ● Guns off depth if packer cannot be set at desired depth.
● Under-balance perforations ● Limited TCP weight capacity
● Only 1 run (TCP⫹ Packer ⫹ DST on the same ● Large Rat hole required to drop the guns
string)) ● Packer rated V3 as of today
● Reduced rig time ● Expensive service charges
● Retrievable seal bore packer, easier abandon ● Requires very experienced personnel and thorough
● By pass valve below packer preparation (i.e casing special drift)
● Guns not connected to DST string
● Gun release feasible
● Short Explosive time exposure

Option 5—Run Permanent Seal Bore Packer on Drill Pipe, Run TCP and DST on tubing, sting through, shoot and Test
Advantages Disadvantages

● Accurate space out ● Smaller gun size thus reducing perforation length and entrance hole
● 2 Runs (Packer ⫹ TCP, then DST string) ● Large Rat hole required to drop the guns
● Easy standard DST operations ● Abandon of the zone through permanent packer is difficult
● Under-balance perforations ● Guns shall provide enough clearance against packer PBR to be
● Gun release feasible pulled out after firing.
● Relatively Short exposure of Explosives at ● Difficult association with standalone wire wrap screen
high temperature
● TCP miss runs easier to manage

well test can be performed with an overbalanced fluid in the annulus. It is wise to note that even the
explosive temperature rating are pushing the limits upward, it is significantly reducing to the perforation
performance (perforation length and entrance hole). A particular attention shall be paid on TCP ancillary
equipment too. Indeed, a 20 Kpsi gun carrier associated with 15Kpsi firing head will downgrade the
overall string to the weakest element rating. Accessories like gun release, control tension release, shock
absorber do not stand high differential or hydrostatic pressures.
Perforation service companies developed simulation software that determine explosive performances
and give a good flavor of what the well productivity would be. Softwares had evolved over time with the
development of wellbore dynamics simulations and shocks induced by the perforation blast. Even though
these are simulation, it gives a good visibility of what is happening during the first few seconds after the
perforation occurs. It helps the well test engineer to optimize the setting depth of the packer if the shocks
OTC-25121-MS 15

are believed to be too severe, beyond what shock absorbers could stand, whether by setting the packer
higher or whether by increasing the rat hole (when feasible).
Stress rock explosives charges has been introduced to the market recently, specifically designed to
address perforations in tight and hard rocks. They shall be given considerations since tight and hard rocks
are frequent in N/E/U HPHT reservoir.
G- Down hole Test Tools
Down-hole Test tools are specialized equipment that are supplied by only two to three premium service
companies in the world. They have been designed and introduced to the market back in the 1920’s and
since then, has evolved to address the N/E/U HPHT market. The tools are designed to handle severe
pressure load cases applying from the outer parts and inner part of the equipment, associated with high
absolute temperature and numerous temperature cycles. They are operated remotely from surface, whether
by applied pressure (direct hydraulic commands), pressure cycles (pressure pulse recognized as command
by an embedded intelligent firmware) or by wireless telemetry digital signal. They tend to be standardized
to sour services as per NACE MR 0175/ISO 15156 norms and can be dressed with dedicated elastomers
covering a wide range of reservoir and completion fluids.
The combination of tools forming a DST string can be from the simplest design to the most
complicated. A simplest design is preferred when temperature are high, thus limiting the amount of valves
cycles. A sophisticated string allows more flexibility during the operation along with the collection of
more physical data (i.e reservoir samples) and digital data (pressure, temperature, down-hole flow
rate,. . .). A DST string shall be designed to perform several major tasks, each of them of equal
importance:
● The safe and efficient deployment in the hole
● The ability to access the perforating system whether mechanically or whether hydraulically
● The ability to open/close the well, collect reservoir physical and digital data
● The ability to access the reservoir when production logging or intervention are planned
● The ability to kill the well and control fluid displacement returns
● The ability to retrieve the string without special intervention

These tasks are successfully performed when testing N-HPHT reservoir. They become more complex
in E/U HPHT environment where the main challenges are the limitation of the DST tools operating
envelope. New generation of Extreme HPHT mechanical DST tools operates at pressure as high as 35
Kpsi (absolute pressure) and 450 Deg F, whereas electronic DST tools are limited to 410 Deg F for the
same pressure rating. This is a great achievement since DST tools are designed to stay in the hole from
2 to 4 weeks under extremely high temperature. When down-hole temperature exceed 375 Deg, it is wise
to opt for a simplified DST string. In this configuration, the Tester Valve and Multi Cycle Reversing Valve
are not part of the string. The aim is to eliminate multi cycle tools since the dynamic seals may deteriorate
rapidly, leaving the valve in an unwanted position (closed tester valve or opened multi cycle reversing
valve). Thus, the simplified string would consist of one or two single shot reversing valve, gauge carriers
(featuring mechanical pressure and mechanical temperature gauges), a tubing tester valve, and a pump
through emergency shut in valve. The latter have been engineered to shut the well down-hole in case of
emergency, in particular when a tubing to annulus leak occurs. Indeed, the additional pressure in the
annulus would cycle the emergency valve and contain the tubing leak, providing the leak occur above the
valve itself. The second role of the emergency shut in valve is to shut the tubing path in order to reduce
the wellbore storage while gauges record the pressure build up response. Nevertheless, the assessment of
this practice must be well evaluated since conventional flapper emergency shut in valve, designed with
a flapper valve, can develop leaks at high differential pressure, therefore spoiling the buildup response.
There are few considerations to take into consideration when engineering a DST string for E/U HPHT
well:
16 OTC-25121-MS

● The operability of the tools during the well clean up and well testing is not seen as a major
challenge. Nevertheless, the number of tool cycles must be limited to the minimum to avoid
unnecessary stress on the equipment, therefore surface shut in are preferred. Multi rate test are also
best fit since the well can flow at different choke size without shutting the well like in the case of
an isochronal test.
● Each down-hole tools shall be dressed with the latest tool upgrade kit. All electronic components
shall be replaced with brand new components to avoid premature failure (the reliability of
electronic devices depends on the time of exposure).
● The well killing can become problematic when the well killing methodology is not appropriate or
when the DST tools are not responding to commands. Therefore, a good engineering of the well
kill procedure shall be in place before hand, along with plans for contingency.
● Retrieving the DST string is far from trivial when DST tools have undergone extreme load cases
for a long time in a very dense packer fluid. A rigorous tubing free strategy shall be put in place
with the aim of maximizing the “over-pull” margin at the first resort and easing the cutting of the
tubing at the last resort.
● The requirement for real time data transmission from down-hole to surface should not be
overlooked since it brings two major benefits, providing down-hole temperature qualifies the
technology: a)-Help to diagnose what is happening down-hole, at the reservoir, DST string and
eventually Subsea. This increase greatly the efficiency of the DST operations and reduce wire-
line/slick line interventions. b)- Reservoir pressure and temperature gathered on real time help to
optimize the DST sequence but as importantly, secure the data in case the DST string cannot be
recovered
H- Equipment qualification and validation
The selection of equipment should be based on existing field proven technology with the simplest design
when possible. At extreme HP or HT, it is wise to test the equipment in a laboratory to validate the
suitability of the selected tools. Candidates are usually the sub elements of a Tubing Conveyed Perforation
string and critical items of a DST string.
Tests are usually conducted at the technology center of the Well Testing Contractor where facilities are
designed to reproduce down-hole conditions (High P and High T), thermal cycles, sometimes shocks, and
vibrations.
These tests are costly, requiring a long preparation time to design and to prepare the facility. Typical
objectives are:
● Validate the operability of each DST tools (at reservoir pressure and temperature for a given
amount of time)
● Validate the pressure integrity of each DST tools (at reservoir pressure and temperature for a given
amount of time), confirm the sealing technology is adequate
● Validate the robustness of each DST tools to handle the more stringent expected Burst and
Collapse load cases
● Optionally, survival or destructive test

When the equipment does not pass the test, back up tools could be tested or the DST design philosophy
should be reassessed. Perforation components are also tested using a similar methodology. Ideally, the test
incorporates all elements of the ballistic transfer (firing head, detonator, booster, detonation cord, and
shaped charge) to be conclusive. The primary goal is not to evaluate the performance of the explosive
itself but get the assurance the system will detonate after prolonged time at high temperature. Primary and
secondary objectives would require additional Quality Assurance and Checks, in addition to what
manufacture normally do. Perforation suppliers owns a good database of laboratory tests, whether
OTC-25121-MS 17

performed in-house, Third party or in conjunction with an operator specific test requirement. This
database could be a good alternative in case a laboratory test cannot be performed due to budget or time
constraint.
I- Well Intervention and Free tubing Strategy
Well interventions are regular practice in exploration well testing. They are perceived as risky when the
well conditions are extreme, in particular when the surface pressure and temperature are very high, when
the reservoir fluids are highly toxic, when the rig installation is in deep waters. They become even more
complex when the well is deep and/or deviated. Under these circumstances, well intervention should be
minimized or even banned. The typical well interventions are as follow:

Typical operations in E/U HPHT Well :[Well Not Perforated – Annulus Pressure under or over balanced]:
Operations Slick Line Wire-line Coil Tubing

Casing drift, depth control, tag bottom Suitable Suitable Not advised
Cement evaluation Not suitable Suitable Not Suitable
Run production packer Not suitable Not suitable if weight Not advised
limitation on cable
Drift tubing, confirm DST valve position Suitable Suitable Not advised
Run TCP Firing head Suitable Not advised Not advised
Perforation string Only if tubing pressure Only if tubing pressure Only if tubing pressure
overbalanced overbalanced overbalanced
Run/set/Unset Xmas tree BPV Suitable Not advised Not advised
Fishing Suitable Suitable Suitable

Typical operations E/U HPHT Well : [Perforated Well – Tubing Pressure underbalanced: Live well]
Intervention Slick Line Wire-line Coil Tubing

Run Pressure and Temperature Gauges Suitable but not recommended Suitable but not recommended Suitable but not recommended
Run Bottom Hole samplers Suitable but not recommended Suitable but not recommended Suitable but not recommended
Perforation string Possible but not recommended Possible but not recommended Possible but not recommended
Production Logging Suitable but not recommended Suitable but not recommended Suitable but not recommended
Fishing Suitable but not recommended Suitable but not recommended Suitable but not recommended
Sand Removal Not suitable Not suitable Suitable but not recommended

Typical operations E/U HPHT Well : [Perforated Well Pressure tubing Over Balanced – well killed]
Intervention Slick Line Wire-line Coil Tubing

Run/set/Unset Xmas tree BPV Suitable Not suitable Not suitable

Mechanical Gun Release Suitable but not recommended Not suitable Not suitable
(Contingency only)
Run Free tubing tools (Chemical cutters, Not suitable Suitable Suitable (Abrasive tubing cutter only)
colliding & severing tools, punchers,. . .)
Run Free point indicators Not suitable Suitable Not Suitable
Dump cement, squeeze formation Not suitable Not suitable Suitable but not recommended
Fishing Suitable Suitable Suitable

Slick line, wire-line and coil tubing operations involved a suitable pressure control equipment that
would be used in case the well is unperforated, perforated or killed. Intervention operations are not
recommended in E/U HPHT (risk of pressure leak, complex operations) and therefore the design of the
test shall be made in such a way operations can be carried out without their needs. There shall be only
contingency plans to recover the DST string in case it cannot be pulled when applying a safe pulling
margin.
18 OTC-25121-MS

There are several ways to free a stuck DST string, not all of them are applicable in E/U HPHT or deep
water operations:
Maximize the over-pull margin: this technique is typically the first to use when the DST string is
stuck in the hole. In the design of the DST sting, the well test engineer will ensure the margin of
over-pull is the greatest. Indeed, the tubing stress analysis will determine the margin based on the
tubing configuration. The weakest element, subjected to the maximum axial load is located below the
surface test tree (or below the subsea test tree, depending how the subsea landing string is configured).
Increasing the tubing size, weight or grade can results in a larger over-pull margin but in some extend,
add more weight to the DST string. A particular attention shall be paid on the surface test tree tensile
strength limitation and all lifting equipment such as elevators, bails, etc. . .
Fatigue the string: this technique is sometimes used on fixed installation. The stuck string is
perforated as deep as possible and then, cycles of over-pull and set down weight applies to fatigue the
metal at the perforation level. After several cycles, the tubing shears because of fatigue and the string
can be pulled out.
Displace abrasives mud: this technique is complementing the previous one. An abrasive mud is
circulated through the opened ports after a tubing puncher operation. As the flow rate and pressure of
circulation increase, the holes are becoming larger thus weakening the resistance of the tubing. A
reduced over-pull margin will then free the tubing.
Use of a DST jar: this technique is commonly used on land and continental shelf operations. Jars are
not adequate in Extreme pressures and temperatures since there are prone to severe leaks, and they
often limited by temperature. Their efficiency in deep water DST operations are questionable.
Use of a Safety Joint: this technique is commonly used on land and continental shelf operations.
Usually placed straight above a tubing wall packer, they back up DST string when a torque is applied
from surface. Safety joints are not adequate when associated with a seal bore packer. In deep water
operations, because of the subsea landing string set-up and the umbilical, torque from surface is very
limited. Indeed, the rotation of the string is difficult with the umbilical in place and the subsea test tree
feature safety pins that shears at low torque.
Run tubing cutter: Tubing cutters are the ultimate solution, used when other techniques has failed to
free the string. The family of tubing cutter is large and continue to evolve over time. There are many
variables to take into account when selecting the right cutting method. In order to make these
operations simpler, the DST string is designed to allow access of the cutter up to the top of the
perforating string (it assume the tester valve is held open and the flapper safety valve has not been
cycled closed). Ideally, the DST string feature a sacrificial joint below and above the packer (a joint
that has a reduced wall thickness). A good practise is to add several pup joint above the DST BHA in
order to ease the correlation. Indeed, some tubing cutter do not allow the use of a wire-line gamma ray
logging tool, therefore the only reliable method is true CCL. The selection of tubing cutter will depend
if a clean cut is required to ease the fishing of the pieces left in hole after the cut or not (colliding/
severing tools versus chemical, plasma, abrasive or electro-mechanical cutters). Tubing cutters are
limited by the hydrostatic pressure rating, the tubing wall thickness, the temperature and somehow the
properties of the completion fluid.
The assumption the DST string will be recovered easily is not always true. Numerous DST BHA (or
part of) have been lost in the hole, even after spending a considerable time to recover them. In N/E/U
HPHT, deep and deviated wells, heavy mud or brine, it is a good practice to build a rigorous tubing
free strategy validated by a Free Tubing On Paper exercise.
Conclusions
Most of the recommendations described in this document have been applied to the design of the Extreme
HPHT DST operations planned for the well KN-X in Malaysia. The management decision to engage
OTC-25121-MS 19

professional well in advance (at least 2 years before the operations) increase the probabilities to succeed.
Indeed there are enough time to engineer and prepare such extreme operations where the road map looks
like the following:
These recommendations are listed to provide guidance to operators that are not familiar with Normal,
Extreme, or Ultra HPHT well testing. They do not constitute a firm guideline since each well and
reservoirs require a customized design. In any cases, the well test engineer would have to assess the best
technology available on the market and use a fair amount of creativity to overcome technical challenges.
The strong support of well testing contractor in each phase of the project is paramount.

Acknowledgement
The authors wish to thank Petronas Carigali for granting the permission to publish this paper.

Nomenclature
Abbreviation
API American Petroleum Institute
BHA Bottom Hole Assembly
BHM Bull Head Margin
BPCV Below Packer Circulating Valve
BOD Basis of Design
BOP Blow Out Preventer
20 OTC-25121-MS

CCL Casing Collar Locator

CO2 Carbone dioxide
DST Drill Stem Testing
ER Extended Reach
H2S Hydrogen Sulfide
ISO International Standard organization
ID Internal Diameter
MSIWHP Maximum Shut in Well Head Pressure
NACE National association of Corrosion engineers
N/E/U HPHT Normal, Extreme, Ultra, High Pressure High Temperature
OBM Oil Based Mud
OD Outer Diameter
PBR Polish Bore Receptacle
PBTD Plug Back Total Depth
PCSB Petronas Carigali Sdn Bhd
PPG Pound Per Gallon
SOBM Synthetic Oil Based Mud
SOR Statement Of Requirement
TCP Tubing Conveyed Perforation
TP Test Pressure
VOI Value of Information
WBM Water Based Mud

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