1. SpecialWells Manual

Drilling and Production Operations
Ref: INDEX
SPECIAL WELLS MANUAL, VOLUME I:
HIGH PRESSURE, HIGH TEMPERATURE
Issue: Feb 2000
INDEX
Page 1 of 1
Introduction
HPHT 01
HPHT Drilling Techniques and General Procedures
HPHT 02
HPHT Well Control Procedures
HPHT 03
HPHT Equipment, Design and Materials
HPHT 04
Drilling Engineering Considerations
HPHT 05
Management and Control
HPHT 06
References and Further Reading
HPHT 07
SECTION 1
Drilling and Production Operations
Ref: HPHT 01
SPECIAL WELLS MANUAL, VOLUME I:
HIGH PRESSURE, HIGH TEMPERATURE
Issue: Feb 2000
INTRODUCTION
Page 1 of 5
TABLE OF CONTENTS
1.
INTRODUCTION.................................................................................................... 2
1.1
DEFINITION OF HPHT .................................................................................... 2
1.2
OBJECTIVE ..................................................................................................... 2
1.3
CODES AND STANDARDS ............................................................................. 3
1.4
HPHT FIELDS AND AREAS ............................................................................ 3
1.5
DIFFICULTIES ASSOCIATED WITH HPHT DRILLING................................... 3
1.6
APPLICATION OF HPHT PROCEDURES....................................................... 4
INTRODUCTION
1.
Page 2 of 5
INTRODUCTION
The planning of high pressure, high temperature (HPHT) wells should be carried out by
very experienced Engineers who have a broad well engineering background. This
document is aimed at these Engineers and therefore, many general well engineering
concepts will not be discussed. Only specific HPHT issues will be described in detail.
It also highlights generic industry practices for consideration and, as a result, many of
the issues are written with a strong emphasis on terms such as ‘will, should and shall’.
1.1
DEFINITION OF HPHT
An HPHT well is both high pressure (pressure control equipment rated in excess of
10,000psi is required) and high temperature (the undisturbed formation temperature at
total depth is greater than 300F).
The main driver is the pressure criterion but temperature effects are significant too. If
only one of these conditions is present, then this document may still apply in
many areas.
HPHT wells require a higher degree of engineering effort and preplanning for well
design, due to the tighter margins between the pore and fracture gradients and the
thermal loads arising from higher temperatures. The project engineering time required
for an HPHT well design may be significantly more than for a standard well. As a result,
it is normal practice to identify and put in place, a specific multidiscipline project team;
well in advance of the anticipated spud date for such wells.
1.2
OBJECTIVE
The objective of this document is to provide Drilling Engineers with a broad outline of
issues associated with the planning and operational execution for an HPHT well. They
should use this document as guidance, in order they know where to obtain the
specialist type of information for an HPHT well and understand the key issues. The
Institute of Petroleum (IP) Model Code of Safe Practice Part 17: Well Control During
the Drilling and Testing of High Pressure Offshore Wells, May 1992, will form the
primary link for this manual, in terms of HPHT well practices and planning. Projects
should therefore be planned on the basis that they satisfy the requirements of IP 17,
and deviations from the document should be explained and justified.
INTRODUCTION
1.3
Page 3 of 5
CODES AND STANDARDS
Codes, Standards and Guidance applicable to HPHT wells are still based on the
traditional range of documents within the oil industry, such as API. However, there are
a number of specific documents that should be used for HPHT wells.
These include, but are not limited to:
Institute of Petroleum (IP) Model Code of Safe Practice Part 17: Well Control during
the Drilling and Testing of High Pressure Offshore Wells, May 1992
National Association of Corrosion Engineers (NACE) MR0175-99: (Assessment of
H2S and CO2)
Institute of Petroleum (IP) Guidelines for ‘Routine’ and ‘Non-routine’ Subsea
Operations from Floating Vessels (Riser analysis, structural strength, integrity of
subsea systems), August 1995
1.4
HPHT FIELDS AND AREAS
HPHT reservoirs have been developed since the early 1970s. Regionally they exist in
the North Sea, North America and mainland Europe but are not yet extensive. There
are HPHT fields in production, or under development offshore UK, offshore Norway,
onshore USA, offshore in Mobile Bay USA, onshore Italy and onshore Austria.
In addition to the HPHT nature, these fields are characterised by:
Great depths
High H2S/CO2 and possibly Mercury levels
High levels of dissolved salts
High drilling and equipment costs
The US fields are predominantly gas, while the North Sea and Italian fields contain high
levels of condensate, or are volatile oils. In the North Sea, most are in the Central
Graben area.
1.5
DIFFICULTIES ASSOCIATED WITH HPHT DRILLING
The main issue of HPHT wells centres around the cost. The combination of depth and
the higher pressures and temperatures will require drilling rigs with a high specification.
Drilling becomes exponentially slower with depth and additional casing strings are
required compared to conventional wells.
INTRODUCTION
Page 4 of 5
Additionally, longer multidiscipline team planning schedules and high-specification
equipment lead-times for equipment such as Non API casing strings, wellheads/xmas
trees and duplex flowlines, all have an impact on the project cost.
The risk of an incident such as a well influx also requires additional emphasis on preplanning, training and operational drilling practices. As a general guide, HPHT wells
experience approximately a two-fold increase in well control incidents, over and above
a conventional well. This has an impact on cost and safety procedures.
1.6
APPLICATION OF HPHT PROCEDURES
The method that should be adopted for HPHT projects requires a multidiscipline
approach for all of the planning and operations. It is unrealistic and inefficient for
disciplines to work in isolation for such projects. It is normal practice that a team will be
identified and formed at the conceptual stage in order to plan, identify areas of concern
and optimise the well design with all of the personnel and companies associated with
the project, prior to commencement of operations. In particular, the drilling contractor
and the main service providers, will become part of the core team at a very early stage,
for risk assessment and contingency planning. The team would look at life of well/field
issues at the start of the project and would consist of drilling, production, reservoir,
petroleum, facilities and completion engineers, together with geological, geophysical
and petrophysics explorationists.
Examples of the application of HPHT procedures are:
Defining a clear envelope for the well design for worst case scenarios eg the
assumption that H2S is present, unless conclusively proven that it is not. All
tubulars potentially exposed to reservoir fluids should be NACE H2S sour service
resistant, to reduce the risk of sulphide stress corrosion cracking. The objective is
to identify the impact of corrosive toxic gases and, where possible, design the
problems out of the system, prior to commencement of operations
Identifying the limitations of the well design to all parties in order that operational
procedures are realistic. For example, highlighting exploration drill stem testing
(DST) thermal limitations, as opposed to long-term thermal production loads
(Exploration v Development)
Utilising teamwork from a variety of disciplines, for critical operations such as long
heavy casing strings. Performing a casing design structural VME (von Mises
Equivalent) Triaxial analysis at the design stage. Focusing on material selection,
premium connector qualification testing, manufacturing and inspection criteria, the
drilling fluid system, casing running procedures and equipment, casing cement
slurry design, capability of the drilling rig derrick system, contingencies etc
Integrating engineering and operations personnel as one team, by defining the well
objectives clearly and recognising the knowledge and skills set of all the key
personnel. This is to ensure there are no gaps in the well engineering processes for
the project for all phases. An example is the inclusion of the drilling contractor for
the development of the project well control procedures and optimisation of drilling
assemblies for the hole sections, to maximise hydraulics and hole cleaning
INTRODUCTION
Page 5 of 5
Focusing on training and human factors for contingencies and emergency response
exercises at an early stage, prior to commencing the drilling of the HPHT transition
zone
Defining interfaces and roles/responsibilities for the operator and drilling contractor
The key message is: ‘The application of HPHT procedures and systems requires the
involvement of all personnel at all levels for planning, operations, contingencies, risk
assessments and emergency response’
SECTION 2
Drilling and Production Operations
Ref: HPHT 02
SPECIAL WELLS MANUAL, VOLUME I:
HIGH PRESSURE, HIGH TEMPERATURE
Issue: Feb 2000
HPHT DRILLING TECHNIQUES AND
GENERAL PROCEDURES
Page 1 of 12
TABLE OF CONTENTS
2.
HPHT DRILLING TECHNIQUES AND GENERAL PROCEDURES...................... 2
2.1
PREPARATION ............................................................................................... 2
2.1.1
Rig Floor Equipment ................................................................................... 2
2.1.2
Well Control Equipment.............................................................................. 3
2.1.3
Downhole Equipment.................................................................................. 4
2.2
DRILLING OPERATIONS ................................................................................ 4
2.2.1
Equipment .................................................................................................. 4
2.2.2
Drilling Practices......................................................................................... 4
2.2.3
Circulating System...................................................................................... 6
2.3
TRIPPING OPERATIONS ................................................................................ 6
2.3.1
Operations Prior to Tripping........................................................................ 6
2.3.2
Operations Whilst Tripping ......................................................................... 6
2.3.3
Operations After Tripping............................................................................ 8
2.4
CORING........................................................................................................... 8
2.4.1
Coring Equipment ....................................................................................... 8
2.4.2
Coring Procedures...................................................................................... 8
2.5
CASING WEAR.............................................................................................. 10
2.6
BOP TESTING ............................................................................................... 11
HPHT DRILLING TECHNIQUES AND
GENERAL PROCEDURES
2.
Page 2 of 12
HPHT DRILLING TECHNIQUES AND GENERAL
PROCEDURES
This section discusses the typical preparation and procedures that would be required
for a high pressure, high temperature (HPHT) well. It assumes the worst case, an
offshore well with a semi-submersible rig.
It should be noted that the issues highlighted as techniques and procedures have a
strong link to IP 17 and generic industry practices.
Depending on the rig type and drilling contractor, many of the areas discussed below
would generally be developed by the operator and drilling contractor. It would be
normal practice subject to legislation and regulations in use around the world, to
identify which well control procedures would act as the base document, for review and
assessment for the HPHT project. Some drilling contractors may have specific HPHT
Drilling Operations and Well Control Manuals for a specific rig. The operator would
normally then include additional issues specific to their requirements, as addenda to
each respective manual, with the consent of the drilling contractor. This would typically
require an HPHT Bridging Document.
2.1
PREPARATION
2.1.1
Rig Floor Equipment
The specific instructions summarised below are a guide to identifying instructions for
drilling equipment:
All pressure gauges used in the drilling and well control circulating system will be
calibrated to ensure they are accurate and consistent
A float valve will not be run in any bottom hole assembly (BHA) after the
intermediate casing is set (typically the 13-3/8in)
A Gray Type non-return valve (NRV) will not be kept on the drill floor but will be
available for use on the rig
A Hydril dart sub will be included in every BHA. The dedicated drop-in dart will be
kept fully serviced in the drillers dog house. The Driller will ensure that, on each trip
out of the hole, the dart sub is checked for damage and erosion. The dart will be
checked that it will pass through every component in the drillstring above the dart
sub, including the stab in valves kept on the drill floor. The dart must be rated for
the temperature and pressures that could be encountered in the well.
Note: During weekly testing of surface equipment, the dart will be installed in the dart
sub and pressure tested as stated within the drilling programme.
Two 15,000psi, full-opening safety valves will be kept on the drill floor with
crossovers, for each type of connection in the drillstring
HPHT DRILLING TECHNIQUES AND
GENERAL PROCEDURES
2.1.2
Page 3 of 12
Well Control Equipment
The choke manifold and blowout preventer (BOP) will be lined up in the following
manner and checked at the start of each shift by the driller:
All failsafe valves closed
Valves lined up to allow flow from the choke line through the autochoke, to the poor
boy degasser, to the liquid seal and on to the header box. Valves must be lined up
for a ‘fast shut-in’. The glycol injection pump will be permanently rigged up to allow
immediate use
The driller will function test the remote actuated valves to the mud gas separator
(MGS) and the MGS bypass line at the start of each shift, and ensure that the
port/starboard directional valves are lined up for the prevailing wind direction
The maximum allowable annular surface pressure (MAASP) control is to be
disconnected at the remote choke control console.
Note: If the MAASP control is activated on the maximum setting, this would open
the choke and allow a continued influx into the well. This can make the well
control situation worse, as this would result in the gas venting off, which in
turn would introduce new influxes into the wellbore ie work on the basis that
fracture at the shoe is preferable.
The slow circulating rate (SCR) pressures are to be taken with the mud pumps and
the kill pump. The kill pump SCR pressures are to be taken with 1/2bbl/min as the
lowest circulating rate using the drill floor remote operating controls. Kick sheets will
be updated after taking the SCR pressures. SCR pressures will be taken at the
remote choke control panel:
At the start of each shift
After changes to the mud weight/properties
After changes to the BHA
Note: The taking of SCRs at the beginning of each shift needs to coincide with the
flushing of choke and kill lines and trip tank, if mud is stored in these
components.
The barytes bulk lines will be purged at the start of each shift. Ensure that the surge
tanks are full at the start of each shift. Bulk storage tanks will be fluffed up once
a day
Both the poor boy and vacuum degassers are to be operated at least once during
each shift. If instrumentation is installed on the dip tube, it is to be checked against
the mud weight on a daily basis
A 15,000psi kill sub complete with spacer sub and chicksan swivel, will be made
up, pressure tested and available on the rig floor at all times
HPHT DRILLING TECHNIQUES AND
GENERAL PROCEDURES
Page 4 of 12
The choke manifold and the MGS temperature and pressure data monitoring
equipment are to be function tested every week. This is to be performed in place
if possible
2.1.3
Downhole Equipment
Non-magnetic drill collars are required in the BHA if survey tools are required, for
directional surveying purposes
The bit nozzle selection will take into consideration the potential for pumping of lost
circulation material (LCM), barytes and cement plugs for control of lost circulation.
The bit nozzle selection will be planned such that the issues of hydraulics and LCM
are considered together. The minimum nozzle size will be 1/2in
2.2
DRILLING OPERATIONS
2.2.1
Equipment
For Kelly Drilling, a safety valve will be used below the kelly so that the kelly can be
safely disconnected, during HPHT well control operations
For Top Drive Drilling, the well will be drilled in singles, using a ‘drilling kelly’
comprising two pup joints with saver subs above and below, separated by a number
of full-opening drillpipe safety valves (at least two). This arrangement will ensure
that the top drive can always be safely disconnected during high pressure well
control operations. (This arrangement would be used at some point prior to the
HPHT transition zone)
2.2.2
Drilling Practices
On any indication of flow, the well will be shut in according to the ‘fast shut-in’
technique. The Driller will be responsible for shutting in the well and will not require
confirmation from the Toolpusher or Operator Drilling Supervisor
Once optimised, drilling parameters will be kept constant to allow rapid identification
of drilling breaks. The Driller will not allow the bit to ‘drill off’ and the compensator
will be kept in mid stroke
When drilling into, or while in an over-pressured formation, drilling parameters will
be controlled, so that not more than one connection gas influx is present in the hole
at any one time
HPHT DRILLING TECHNIQUES AND
GENERAL PROCEDURES
Page 5 of 12
When oil based mud (OBM) is used, drilling breaks of 5ft will be flow checked for a
minimum of 15 minutes. If the flow check indicates no flow, drill an additional 5ft
and if the drilling break continues, circulate bottoms up before drilling ahead.
Circulate bottoms up, shutting in the well as bottoms up is c. 1,500ft below the
BOPs. When water based mud (WBM) is in use, flow checks will be for a minimum
of 5 minutes, or until it is established that the well is not flowing
Drilling parameters will be continuously monitored by both the mud logging and rig
sensor packages. Any discrepancies between the two systems will be investigated
and rectified. Any deviation between physically observed parameters and monitored
parameters will also be investigated
The temperature of the mud returns will be monitored at the header box at all times.
Any changes to the temperature trend will be fully investigated. The implication of
the changes on the maximum continuous working temperature rating of the
elastomer goods will be discussed and corrective action taken as necessary.
Drilling operations will be suspended if the temperature of mud returns at surface
exceeds an agreed maximum or if the temperature measurement system fails
Note: *The limits will be set down by the drilling contractors operations manual and
agreed with the operator as part of the HPHT bridging document.
When operations dictate that a sample requires to be circulated to surface for
investigation, the following will be used as a precautionary measure to prevent
sudden release of gas at surface. The well will be shut in on the upper annular
when the sample is c.1,500ft below the BOPs and directed through the choke line
and over a full-open choke. Circulation will continue until the sample is out of the
well and gas levels return to a normal level, or shut-in procedures have to be
initiated
If drilled, connection or trip gas levels in the mud increase significantly, then the
well should be shut in on the upper annular and circulation continued through an
open choke to the poor boy degasser (taking into account choke line losses). The
well will be circulated in this manner until the gas levels have normalised. If gas
levels do not return to normal levels, further action may be required and discussed
with onshore operational personnel (Drilling Superintendent)
Whilst drilling into, or in a overpressured transition zone, the mud weight will be
increased in accordance with the indications of overpressure. If the pressure
transition zone occurs in a low permeability limestone formation, the most reliable
method of detecting overpressure is increasing gas levels. The background gas
level will be normalised by the Mud Logger for penetration rate and circulation rate,
so that a reliable trend can be followed. Drilling will stop and mud weight increased
if the continuous normalised background gas levels increase above 5%. Drilling will
not continue until the background gas level has been reduced to the previous level
HPHT DRILLING TECHNIQUES AND
GENERAL PROCEDURES
2.2.3
Page 6 of 12
Circulating System
Mud weights in and out and pit levels are to be monitored and recorded every
15 minutes. When recording the mud weight, the temperature at which the mud has
been weighed must be stated and corrected to a specific reference temperature.
A graph should be constructed identifying the change in ‘mud density variation with
temperature’ at surface to highlight the reduction in mud weight as the temperature
increases
Additions to the active system will only be made by the Mud Engineer. All additions
will be discussed with the Drilling Supervisor, Toolpusher, Driller and Mud Logger
prior to implementation. Mud transfer operations will not be conducted on the active
system while drilling into, or in overpressured formations. If a mud transfer is
necessary, drilling operations will be suspended until the operation has been
completed and the pit levels have been established
2.3
TRIPPING OPERATIONS
2.3.1
Operations Prior to Tripping
Determine the maximum pipe speed, taking into account swab/surge pressures.
These figures will be given to the Driller prior to tripping operations
The Driller should line up the trip tank and fill in a trip sheet. A trip sheet from the
previous trip out of the hole should be available
The Toolpusher will provide the Driller with written instructions containing the
necessary information about the trip, ie reason for trip, prevailing pore pressure
regime and tripping overbalance, and ensure that the Driller and crew are fully
aware of the correct well control procedures while tripping
The Driller is to ensure that the rig floor is fully prepared to shut in the well, a
drillpipe safety valve is nearby and fitted with the correct crossover and the drop-in
dart is ready for use. Ensure that the dart passes through the safety valve
All efforts will be made to cure any static losses to the well, prior to tripping out of
the hole
2.3.2
Operations Whilst Tripping
A wiper trip back to the last casing shoe should be performed to confirm that pipe can
be pulled out of hole (POOH) safely and to confirm by circulating bottoms up after
wiper trip that there is sufficient trip margin (assessed by monitoring the bottoms up
gas levels). More detailed instructions for the wiper trip are as follows:
Prior to tripping whilst using OBM systems, perform a 15 minute flow check across
the trip tank to ensure that the well is stable. In WBM systems, flow check for a
minimum of 5 minutes and until the well can be confirmed to be static
HPHT DRILLING TECHNIQUES AND
GENERAL PROCEDURES
Page 7 of 12
Pump a heavy slug to avoid a wet trip and resultant uncertainty concerning fluid
flow volumes. Calculate the slug size and return volume to give c.200ft of dry pipe.
Allow slug to stabilise, with the top drive/kelly disconnected and ensure that the
correct volume of fluid returns as the slug equalises.
Note: The rule-of-thumb for a non-tapered drillpipe string on return mud volume
due to pumping a slug is:
Slug Volume (bbl) x (Slug Weight (ppg)/Mud Weight (ppg) – 1) = Extra Mud
Volume at Surface (bbls)
Start pulling out of hole to the shoe, monitoring the drop in fluid level. Do not fit a
pipe wiper until the hole fill has been confirmed
If the hole is not taking the correct volume of fluid, carry out the following:
Stop tripping
Install a full opening safety valve
Flow check the well in OBM systems for a minimum of 15 minutes across the
trip tank. In WBM systems, flow check for a minimum of 5 minutes and until the
well condition (static, or flowing) is established
If static:
Run in hole (RIH) to bottom, monitoring hole volumes with the trip tank.
While circulating bottoms up, shut in the well as bottoms up is c. 1,500ft below the
BOP.
If flowing:
Initiate shut-in procedures.
Refer to the Well Kill Decision Tree.
Assuming the flow check is confirmed acceptable, continue tripping out of hole to
the casing shoe and perform a minimum of a 15 minute flow check in OBM systems
across the trip tank. In WBM systems, perform a minimum of a 5 minute flow check,
or until the well kill can be established as being static
Then run back to bottom, monitoring hole volumes and taking into account surge
pressures. Circulate the hole ensuring the first slug is circulated out. Close in the
well when bottoms up is c. 1,500ft below the BOP. Watch out for a pit gain as any
gas comes out of solution. If necessary, increase the trip margin and perform
further check trip. In some circumstances, it may be required to pump out of the
hole
Once a trip margin has been established, drop survey barrel if applicable. Start the
trip out of hole and perform periodic 15 minute flow checks at casing shoe and prior
to pulling BHA through BOP
HPHT DRILLING TECHNIQUES AND
GENERAL PROCEDURES
Page 8 of 12
If the trip is interrupted for any reason, install the drillpipe safety valve. If the hole fill
pump fails during the trip, do not fill the hole through the drillpipe
Whilst the drillstring is out of the hole, the blind/shear rams will normally remain
open. The well will be monitored by circulating across the hole with the trip tank. If
the blind/shear rams are closed, the well will be monitored by circulating across the
BOP by pumping down the kill line and up the choke line with returns to, and
suction from, the trip tank if possible (subject to the BOP configuration)
If a 7in liner has been run, the following additional procedure will be performed. The
reduced clearance between the drillstring and the 7in liner will increase the
likelihood of swabbing whilst tripping. For this reason, the check trip performed as
part of a trip out of hole should be extended past the shoe to the top of the liner.
When pulling out of a hole with a tapered 3-1/2in to 5in drillstring, additional flow
check procedures for the OBM, or WBM systems will be performed:
When the bit is at the liner overlap
Prior to the 3-1/2in drillpipe entering the BOP
2.3.3
Operations After Tripping
When back on bottom, prior to further drilling or coring, circulate bottoms up to
check for gas. Circulate the hole until bottoms up are c.1,500ft from the BOP. Shut
in and circulate out through a fully opened choke
2.4
CORING
2.4.1
Coring Equipment
A circulating sub will be run above and as close to the core barrel as possible
Ensure both the core barrel and circulating sub ball will pass through all restrictions
in the drillstring
The inner core barrel is to be perforated, or have a pressure-relieving device
installed to avoid pressure being trapped in the barrel
2.4.2
Coring Procedures
For exploration drilling, the length of the core barrel to be run in a new reservoir
section will be a maximum length of 90ft for the core barrel. Subject to the
operational trip out of the hole having no problems, the length may be increased
based on a local risk assessment and approval from the Drilling Superintendent
and drilling contractor. If the well is appraisal, or development with good offset data,
these criteria may be modified, subject to the well design and operational conditions
HPHT DRILLING TECHNIQUES AND
GENERAL PROCEDURES
Page 9 of 12
Note: Coring operations will not be performed if there is a high probability of
encountering an overpressured transition zone.
The hole will be circulated and the mud conditioned, prior to the core ball being
dropped
Attention will be given to the calculation of swab pressures and critical tripping
speeds, prior to pulling out of the hole with the core barrel
Coring operations will only be undertaken when there is confirmation that the
objective sand has been penetrated
After penetrating the objective sand, coring operations will only be undertaken if a
10 stand check trip confirms there is sufficient overbalance, prior to tripping out of
the hole
After cutting the first core, tripping procedures will be used as discussed in
Section 2.3
When recovering the core barrel, the following tripping procedure will be used:
POOH to c.1,500ft below the BOPs
RIH to c.3,000ft below the BOPs. Shut in the well as a precautionary measure to
prevent sudden release of gas at surface. The well will be shut in on the upper
annular and directed through the choke line and over a full open choke.
Circulation will continue until the sample is out of the well and gas levels return
to a normal level, or shut in procedures have to be initiated
POOH to c.1,000ft below the BOPs
RIH to c.3,000ft below the BOPs. Shut in the well and repeat the exercise of
circulating out any potential gas through the choke manifold
If hole stable and gas levels normal, POOH to surface
Monitor drill floor and surrounding area with H2S monitors
Prior to recovering the core to surface, clear the drill floor of non-essential
personnel and ensure all personnel ‘mask up’ with breathing apparatus (BA) sets
on the assumption that H2S is present in the core. The BA sets will not be removed,
unless there is clear evidence that H2S is not present. The same procedures will
apply to the handling of repeat formation test (RFT) samples and side-wall cores.
HPHT DRILLING TECHNIQUES AND
GENERAL PROCEDURES
2.5
Page 10 of 12
CASING WEAR
Casing wear from drillpipe rotating can cause a significant impact on the strength of the
casing, which may lead to weakening, down-rating and ultimately rupture, during
pressure testing. This can lead to delays in the project and require the installation of a
contingency tieback. Casing wear is also discussed within Section 3 of the Casing
Design Manual.
The locations most susceptible to wear are doglegs in the upper part of the hole, where
high tension loads in the drillstring hold the rotating tool joints against the casing. As
the tool joints gall and grind their way into the casing wall, a crescent shaped groove is
produced, deepening as drilling progresses. For HPHT wells this has an impact
primarily on the intermediate and the production casings, as they will experience the
most rotating revolutions during the drilling of the well (deeper drilling becoming
exponentially slower).
In terms of risk to the well, casing wear needs to be addressed on two fronts, design
and operational monitoring.
The risks can be minimised at the design stage by consideration of the following:
Establish strict dogleg severity limits, especially near the wellhead
Run heavier wall casing directly at the sections that casing wear is anticipated to be
highest, eg below the wellhead connection, for an evaluated length
Ensure the pre-tender rig audit identifies the type of hardbanding in use for the
drillpipe tool joints
Identify the ‘wear factors’ that may occur from the mud type in use (oil based or
water based)
Estimate the planned total rotating hours and speed anticipated inside the casing,
for all operations
Include a casing wear safety factor as part of the casing design
Utilise a proprietary casing wear software planning programme, prior to the start of
the project
Design and agree drilling practices with the drilling contractor as part of the well
programme
The risks can be minimised at the operational stage, by consideration of the following
procedures:
Ensure the correct hardbanding on the tool joints of the drillstring is utilised across
the areas of anticipated wear
Ensure the inclination of the BOP system/wellhead is limited to a maximum of
1 degree
HPHT DRILLING TECHNIQUES AND
GENERAL PROCEDURES
Page 11 of 12
Consider the use of a baseline multi-fingered caliper log or equivalent, in
combination with a cased hole North Seeking Gyro, in the last casing above
the reservoir
Spend time to minimise ‘localised doglegs’ at or near surface. In particular, at the
wellhead area. This should be linked to the survey programme frequency, as it is
becoming more common to utilise measurement while drilling (MWD) systems even
for certain types of vertical exploration wells
Consider the use and optimum placing of drillpipe protectors in the region where
high wear is expected
Install two high grade ditch magnets in the return stream header box. Collect and
measure the steel samples to establish a trend analysis, in order to identify if there
is a wear problem
The amount of wear on the wellhead and flex joint wear bushings will be measured
and recorded each time the BOPs are pressure tested
If significant wear is suspected in the last casing string prior to entering the
overpressured transition zone, consider the running of a multi-fingered caliper log,
followed by a pressure test of the casing
Feed back the casing wear monitoring results into the well design, to check if the
actual results has an impact on the design factors
2.6
BOP TESTING
The requirements for BOP testing will need to be agreed and finalised by the operator
and the drilling contractor, as part of the well programme. The frequency of BOP tests
will also depend very much on the specific policies of the drilling contractor’s
operations manual and the operator’s internal policies.
For an HPHT well it is probable that the main BOP system will be rated to 15,000psi.
For a semi-submersible this may be a single 18-3/4in system, whereas a jack-up may
be a two-stack system, comprising a 21-1/4in x 5,000psi BOP and 13-5/8in x 15,000psi
BOP. The IP 17 document discusses the issues associated with Testing and Inspection
of Pressure Control Equipment under Section 4.11 and should be referred to as a
datum.
There will be specific milestones where the BOP system and glycol injection line will be
pressure tested. These may typically include the following:
On the pressure test stump to the full rated working pressure for all components,
prior to first nipple up
At intervals not exceeding an agreed timeframe with the drilling contractor,
typically 14 days
Prior to drilling out of the casing shoe
HPHT DRILLING TECHNIQUES AND
GENERAL PROCEDURES
After installation of wellhead seal assemblies
After completion of repair work on the system
Page 12 of 12
Note: Annulars will generally be tested to c.70% of their rated working pressure once
installed.
The rams will generally be tested to a value, greater than the maximum
anticipated shut-in wellhead pressure.
If an annular has been used during a stripping operation, then it will be re-tested on
completion of the well control operation. If it is not possible to obtain a satisfactory
pressure test, then the lower marine riser package (LMRP) will be retrieved and the
annular inspected/repaired assuming the rig is a semi. This will require a temporary
well suspension. This will typically consist of the following:
A cement plug tagged and pressure tested to a value greater than the leak off
test (LOT) across the deepest casing shoe, plus
A kill weight mud, plus
A retrievable packer fitted with a storm valve and adequate length of drillpipe,
set directly beneath the wellhead
If flexible lines are used as high pressure choke and kill lines, the IP 17 document
Section 5 should always be used to check that issues such as storage, handling,
transportation, inspection, annual survey, pressure testing and repair are taken into
consideration. The capability and integrity of the hoses will be part of the drilling
contractor’s rolling maintenance and survey programmes based on annual and
major surveys at five-yearly intervals. They will form part of the rig pre-tender audit
checklist, prior to the start of the project. In particular, it is important to obtain
evidence of the working history of the flexible lines, eg well control incidents,
maximum pressure experienced and type of fluids used
SECTION 3
Drilling and Production Operations
Ref: HPHT 03
SPECIAL WELLS MANUAL, VOLUME I:
HIGH PRESSURE, HIGH TEMPERATURE
Issue: Feb 2000
HPHT WELL CONTROL PROCEDURES
Page 1 of 11
TABLE OF CONTENTS
3.
HPHT WELL CONTROL PROCEDURES .............................................................. 2
3.1
HPHT WELL CONTROL PHILOSOPHY.......................................................... 2
3.2
HPHT SHUT-IN PROCEDURES ...................................................................... 3
3.2.1
Influx Whilst Drilling. ................................................................................... 3
3.2.2
Influx Whilst Tripping .................................................................................. 3
3.2.3
Influx While Out of Hole.............................................................................. 4
3.3
CONFIRMATION OF INFLUX .......................................................................... 4
3.3.1
Drilling Operations ...................................................................................... 4
3.3.2
Tripping Operations .................................................................................... 5
3.3.3
Determining Size of Influx........................................................................... 5
3.4
PRE-KILL MEETING........................................................................................ 6
3.5
HPHT WELL KILL PROCEDURES.................................................................. 7
3.5.1
Bullheading................................................................................................. 7
3.5.1.1
Preparation ................................................................................................ 7
3.5.1.2
Procedures ................................................................................................ 8
3.5.2
Bit on Bottom.............................................................................................. 9
3.5.2.1
Preparation .............................................................................................. 10
3.5.2.2
Procedures .............................................................................................. 10
3.5.3
Tapered Drillstring .................................................................................... 11
HPHT WELL CONTROL PROCEDURES
3.
Page 2 of 11
HPHT WELL CONTROL PROCEDURES
It should be noted that the issues highlighted here as procedures have a strong link to
IP 17 and generic industry practices.
3.1
HPHT WELL CONTROL PHILOSOPHY
It would be normal practice for the operator and drilling contractor to jointly develop a
‘HPHT Well Control Bridging Document’ for a high pressure, high temperature (HPHT)
well based on satisfying the generic requirements of IP 17 (Section 2.4 and 2.5 for
shut-in and well kill procedures).
During the development of the bridging document, well control simulation studies would
be carried out for the well design, based on various influx scenarios for the proposed
mud system. It is important to note the different behaviour characteristics of oil based
mud (OBM) as opposed to water based mud (WBM). The purpose of the simulations
would be to confirm the capabilities of the rig surface equipment to safely handle a well
control incident and confirm if hydrates could occur at the blowout preventer (BOP) well
control system. The outputs of the studies would normally be included as an appendix
and used in estimating glycol injection volume requirements.
It is also important to understand that the key philosophy for HPHT wells is to
minimise the influx volume early, as the expansion at surface caused by a kick from
an HPHT well can be very large compared to the same influx volume for a
standard well.
Therefore, the following issues should be considered based on links to IP 17
Section 2.5 and generic industry practices:
The well will be shut in on any sign of flow, using the ‘fast shut-in’ method to
minimise the influx volume. The valve immediately upstream of each choke shall be
kept closed
After shutting in the well, the choice of well control technique used to kill the well will
depend upon the manner in which the kick was taken and the decision tree
developed by the operator and drilling contractor (Based on IP 17, Driller’s Method,
Wait and Weight Method, Bullheading and Volumetric Method)
The bullheading technique has proved successful in dealing with discrete kicks,
such as those swabbed in while tripping. Kicks taken while drilling may prove
difficult to bullhead, as the influx will be mixed with the drilling fluid. The degree of
dispersion into the mud is related to the time that the well is allowed to flow, before
the pumps are shut down and the rate at which the influx enters the well (ie the well
productivity). Additionally, if high H2S levels are a possibility, bullheading may prove
a more desirable option than bringing the fluids to surface
Attempt to minimise the volume of hydrocarbons reaching surface
To limit surface pressures, temperatures and gas volumes to within the safe
handling capacities of all the individual components of the BOP system
HPHT WELL CONTROL PROCEDURES
Page 3 of 11
To vent or flare gas at surface, in a controlled and safe manner
Do not assume that there will be sufficient warning, such as background gas, while
drilling through the transition zone
When background gas reaches an arbitrary level (agreed with drilling contractor in
the bridging document), all work permits will be withdrawn and the standby boat
notified accordingly
3.2
HPHT SHUT-IN PROCEDURES
The following points summarise the key issues to consider for shut-in procedures,
assuming a semi-submersible with a top drive system.
3.2.1
Influx Whilst Drilling
Stop drilling
Pick up off bottom and switch off pumps
Open the failsafe valves in the upper chokeline and close the upper annular
Check well is shut in
Record initial closed in drillpipe and annulus pressures. (Assistant Driller
assembles crew at rig floor)
Notify the Toolpusher and Operator Drilling Supervisor
Check string space out
Close upper pipe rams
Adjust annular closing pressure
Land drillstring and hang off on upper pipe rams
Close ram locks
Determine influx volume and prepare to kill well
3.2.2
Influx Whilst Tripping
Set pipe in slips with tool joint at rotary table, checking no tool joint across pipe
rams
Install the full opening, drillpipe safety valve
Close safety valve
Open the failsafe valves in the upper choke line and close the upper annular
HPHT WELL CONTROL PROCEDURES
Page 4 of 11
Check well is shut in
Record initial closed in annulus pressure. (Assistant Driller assembles crew at rig
floor)
Notify the Toolpusher and Operator Drilling Supervisor
Make up and install the well kill circulating assembly
Check space out
Close upper pipe rams
Adjust annular closing pressure
Land drillstring and hang off on upper pipe rams
Close ram locks
Open drillpipe safety valve and record pressures
Prepare for well kill and to strip in. (The pump down dart may need to be pumped
down to achieve this)
3.2.3
Influx While Out of Hole
Open the failsafe valves in the upper chokeline and close the upper annular
Close shear rams
Close shear ram locks
Record initial closed in pressure. (Assistant Driller assembles crew at rig floor)
Notify the Toolpusher and Operator Drilling Supervisor
Assess well kill options: Stripping in, Volumetric method, Bullhead
3.3
CONFIRMATION OF INFLUX
If doubt exists as to whether or not an influx has occurred, the following key issues
should be considered
3.3.1
Drilling Operations
In some circumstances it is possible that pressure, in excess of that caused by the
kick zone, can be trapped in the well. This can be caused by:
Pumps left running after well shut-in
Influx is migrating up the hole
HPHT WELL CONTROL PROCEDURES
Page 5 of 11
Pipe has been stripped into well, without bleeding correct volume of mud
If trapped pressure is suspected carry out the following:
Ensure accurate pressure gauges are fitted to the drillpipe and annulus,
carefully monitor drillpipe and casing pressure
Using a manual choke, bleed a small volume of mud from the annulus to a
suitable measuring tank
If both drillpipe pressure and casing pressure have decreased, continue to
bleed mud from well in increments
When the drillpipe pressure no longer decreases as mud is bled from the well,
record the drillpipe pressure as the shut-in drillpipe pressure (SIDPP). Stop
bleeding mud from the well
If SIDPP or/and shut-in casing pressure (SICP) are present, circulate out the
potential influx maintaining a constant bottom hole pressure
If there are no shut-in pressures, circulate until the potential influx is c.1,500ft below
the BOP. Close the BOP and continue circulating through an open choke
3.3.2
Tripping Operations
If there are no shut-in pressures, open up the well and flow check for 15 minutes. If
no flow exists, run in hole (RIH) to bottom and circulate the hole until the potential
influx is c.1,500ft below the BOP. Close the BOP and continue circulating through
an open choke
If either SICP or SIDPP is detected, then the drillstring will have to be stripped back
to bottom and the influx circulated out of the well, maintaining a constant bottom
hole pressure
3.3.3
Determining Size of Influx
The kick size will be determined from the pit gain at surface, checked and
confirmed with the Mud Loggers. The classification of the kick will be made by
analysis of the shut-in casing and drillpipe pressure profiles over time and the
pit gain
The pit gain at surface provides a guide to the volume of the kick. With this
information, together with the annular geometry and surface pressures, it is
possible to estimate the influx density. The following is a guide:
Gas:
0.05 to 0.2psi/ft
Oil:
0.3 to 0.4psi/ft
Water:
>
0.4psi/ft
HPHT WELL CONTROL PROCEDURES
Page 6 of 11
It is recommended all kicks are assumed to contain a certain proportion of gas.
Bottom hole pressure estimates may also be improved by taking into account
corrections to the mud density, for compressibility and thermal expansion.
3.4
PRE-KILL MEETING
Prior to conducting well kill operations it is normal practice to hold a pre-kill safety
meeting before commencing with the well kill.
After the well is shut in, secured and pressures monitored, a pre-kill safety meeting
will be held with the following personnel:
Drilling rig Offshore Installation Manager (OIM)
Drilling contractor Toolpusher
Operator Drilling Supervisor
Operator Drilling Engineer
Mud Engineer
Cementing Engineer
Mud Logging Engineer
At the safety meeting, clear lines of responsibility and communication will be
discussed and confirmed, relative to the well control bridging document
The following critical parameters need to be considered prior to making the final
well kill decision:
Clear understanding by all parties of the maximum anticipated surface volumes
and surface pressures that will occur during the well kill operation
The anticipated likelihood of hydrate formation under the anticipated surface
and wellhead conditions. The hydrate formation curve that was prepared as part
of the well control pre-planning simulations can be used as a guide for the
conditions under which hydrates will form
The critical slow circulating rate (SCR) for the poor boy degasser pressure can
be estimated for varying slow circulating rates to ensure that the operating
pressure is not exceeded and the liquid seal is not broken. (The poor boy
degasser performance curve, will form part of the well control bridging
document.) An optimum circulating rate can then be selected which will
minimise surface pressures and pipe erosion and will not reduce the integrity of
the mud gas separating equipment
Temperature drops across the adjustable choke (where preparations may have
to be made to heat the choke manifold). The predicted temperature drop across
the adjustable choke will form part of the agreed well control, bridging document
HPHT WELL CONTROL PROCEDURES
Page 7 of 11
The likely effect of the chosen SCR on the surface pressures and the volume of
free gas at surface
When all information has been collated, the well kill plan will be agreed and
communicated to all personnel onshore and offshore; to ensure all key issues are
identified and understood
3.5
HPHT WELL KILL PROCEDURES
The operator and drilling contractor will jointly develop the various types of well kill
procedures and decision trees at an early stage, as part of the HPHT bridging
document.
3.5.1
Bullheading
Bullheading may be the preferred option for one or more of the following reasons:
When a very large influx has been taken, especially where there are doubts
regarding the volumes in the annulus
When a kick has been taken off bottom and it may not be possible to strip in all the
way to bottom
When displacement of the influx by conventional methods may cause excessive
pressures, or volumes of gas at surface
If the influx contains unacceptably high H2S levels that could create additional
hazards at surface, to personnel and equipment
If rapid pressure increases require prompt action
If the open hole section is short. This depends upon the characteristics of the open
hole section, to ensure fluid is not being bullheaded higher up in the hole, above the
point of the initial well influx
3.5.1.1
Preparation
The following information should be recorded and available, prior to drilling into the
high pressure transition zone:
Limiting pressures for bullheading that may affect the integrity of the wellbore
pressure vessel, including:
The last leak off test (LOT) data, the working casing burst pressure (excluding
allowances for casing wear and temperature etc) and the pressure operating
envelope of all surface equipment
HPHT WELL CONTROL PROCEDURES
Page 8 of 11
Once it has been established that an influx has entered the wellbore and a decision
has been made to bullhead, the following information should be known, prior to
commencement of operations:
The size of the influx and its location in the wellbore
The location of the weak zones in the open hole section and the consequence of
fracturing the formation(s)
The estimated fracture pressure of the reservoir. This should be used with the
current mud hydrostatic pressure to determine the surface fracture pressure
The type of influx and the estimated relative permeability of the formation
The quality of the filter cake at the permeable formation
The stabilised drillpipe and annulus pressures, to establish actual formation
pressure
With the information available, annulus pressure profiles should be calculated at points
of interest, for various bullhead pressures at surface. From this, a maximum injection
pressure should be established. The volume to be bullheaded will depend on both the
volume of the influx and the way in which the influx was taken. An influx taken while
drilling may be strung out in the drilling fluid (subject to mud type, OBM or WBM) and
so may require a bullhead volume greater than the influx volume.
This can be calculated using the circulating rates at the time of the influx, together with
the rate at which the influx was taken and the time taken to shut in the well.
An influx that is swabbed in while tripping can be sized and the bullhead volume should
equal the influx volume.
It is important to note that the above issues and information can and should be worked
as well planning scenarios, during the well design and programme development. This
would be performed utilising commercially available computer well control simulators
and software.
3.5.1.2
Procedures
Ensure sufficient mud of the current weight is available for the operation and that
the line to the kill pump suction is clear
Line up the BOP and choke manifold to pump with the kill pump down the kill line,
through the lower kill failsafe valves. Ensure surface equipment is pressure tested
to above the maximum injection pressure
Start the bullhead operation at a slow rate such that the volume versus pumping
rate can be monitored. Attempt to keep the rate constant during the operation and
plot the volume versus pumping rate in a similar way, as the leak off graph.
Allow for compressibility of the mud as the pressure is brought up to the
injection pressure
HPHT WELL CONTROL PROCEDURES
Page 9 of 11
As bullheading continues, surface pressure should decrease as the mud displaces
the influx. Surface pressures should be monitored and plotted at regular intervals to
check that the influx is being bullheaded away. If the injection pressure does not
fall, it may be as a result of mud being injected into a formation above the influx
The injection pressure may increase during the operation as the permeability of the
reservoir is damaged. If the injection pressure approaches the maximum allowable
surface pressure, stop the pumps and allow pressure to stabilise. Recommence at
a slower rate, keeping within the maximum pressure limits.
If it becomes impossible to bullhead without exceeding maximum pressure limits ie
fracture pressure, the decision to continue bullheading in excess of this pressure
will depend upon the volume of the remaining influx and the position of the bit in
the hole.
Once the calculated volume of influx has been bullheaded back to the formation,
bleed off any trapped pressure and shut in the well to monitor drillpipe and casing
pressures
If the shut-in pressures have fallen, it may be reasonable to assume that the
operation has been successful. It should be remembered that if the kick was taken
while drilling, it is unlikely the drillpipe and casing pressures will be the same due to
the dissemination of the influx in the mud (subject to mud type, OBM or WBM).
If the bullheading was seen to be successful, then it should be continued until the
drillpipe and casing pressures are similar. The subsequent well kill operation will
depend on how the kick was taken and will be influenced by the following:
If the influx was taken while drilling, then the well can be killed utilising the
original shut-in pressure information
If the bit is off bottom, then it will be necessary to strip back to bottom using
standard stripping procedures. A circulation should then be performed
maintaining a constant bottom hole pressure, to clear the wellbore of
disseminated gas
If the bullhead procedure is not seen to be successful, then consideration will have
to be given to:
Stripping back to bottom and circulating out the influx at a rate dependent on its
size and limitations of the surface equipment
Initiating operations for the suspension of the well
3.5.2
Bit On Bottom
The well kill process and decision tree will have been prepared as part of the well
programme with all relevant parties. In particular, for well suspension and evacuation:
Suspension of the well kill operation, if the temperature measured upstream of the
choke manifold exceeds a pre-determined maximum, or if the temperature
monitoring system fails
HPHT WELL CONTROL PROCEDURES
Page 10 of 11
Note: *This figure value will depend on the type of rig, specific policies in use by
the drilling contractor. A different drilling contractor may specify a lower limit.
This would be identified as part of the rig audit prior to acceptance, as it may
require a rig upgrade with possible costs.
Evacuation procedures are to be in place and initiated as part of the contingency
plan, if choke pressures rise unexpectedly when circulating out a kick. (Surface
pressure profiles during well control are to be calculated in advance)
3.5.2.1
Circulating out an influx through the rig surface pressure equipment, is a standard
well control procedure. In dealing with high pressure gas condensate influxes,
consideration must be given to the large volumes of gas liberated at surface and
the stresses this imposes on the surface equipment. As highlighted in the previous
section, the bullheading technique can be used to reduce the influx volume
whenever possible
3.5.2.2
Preparation
Procedures
The initial stages of the well kill circulation will be as a standard well kill method. At
all times during the circulation, monitor the choke manifold and, if available, the
BOP temperature. If at any time the temperature approaches the defined limit by
the drilling contractor (eg 220F at the choke manifold, or 250F at the BOP), the
pumps should be stopped and a slower SCR selected
Note: Use should be made of temperature charts based on the maximum anticipated
temperatures in the choke line, for the various hole sizes. These would normally
be prepared as part of the well thermal simulations for the well design and well
control bridging document.
Special precautions and procedures are required once the top of the influx is
c.1,500ft from the BOP:
Reduce the SCR to the critical predetermined value
Commence injection of glycol at the BOP choke manifold. (The rate of injection
will have been calculated previously as part of the well planning)
As the gas reaches the choke, monitor the differential pressure between the
mud gas separator (MGS) and the liquid seal
The reading on the liquid seal hydrostatic pressure gauge indicates the maximum
operating pressure of the MGS. In the event of failure of this sensor, or if it proves
to be unreliable, the maximum operating pressure of the poor boy degasser will be
equivalent to the liquid seal being filled with a gas cut condensate, having a
0.3psi/ft gradient. (It cannot be assumed that the liquid gradient in the dip tube is
mud. At best, the mud gradient is likely to be heavily gas cut. At worst, it is likely to
be a gas cut condensate, with a gradient of 0.3psi/ft)
HPHT WELL CONTROL PROCEDURES
Page 11 of 11
Note: The limitations and efficiency of the poor boy degasser will be determined
between the drilling contractor and operator at the well planning stage,
based on the separation capacity of the MGS and the blowdown capacity.
(The blowdown capacity of a MGS is that flowrate which is sufficient to
cause enough pressure to blow out the liquid seal at the base of the MGS).
If either the buffer tank or MGS approach their maximum agreed operating
pressure, then:
Close the choke
Shutdown the pumps
Allow pressure to dissipate in the MGS
Restart circulation at a lower SCR
3.5.3
Tapered Drillstring
If a drilling liner was installed to allow the well to progress, such as 7in, a tapered
drillstring will be required. A well kill with a tapered string is different from a
conventional single string. The drillpipe pressure does not decrease linearly with
the pump strokes because of the different capacities of the two drillpipe sizes
SECTION 4
Drilling and Production Operations
Ref: HPHT 4
SPECIAL WELLS MANUAL, VOLUME I:
HIGH PRESSURE, HIGH TEMPERATURE
Issue: Feb 2000
HPHT EQUIPMENT, DESIGN AND
MATERIALS
Page 1 of 16
TABLE OF CONTENTS
4.
HPHT EQUIPMENT, DESIGN AND MATERIALS.................................................. 2
4.1
BOP EQUIPMENT ........................................................................................... 2
4.1.1
BOP Equipment.......................................................................................... 2
4.1.2
Choke and Kill Lines ................................................................................... 2
4.1.3
Choke Manifold........................................................................................... 3
4.1.4
Hydrate Suppressant Injection Facilities ..................................................... 3
4.2
SURFACE GAS HANDLING FACILITIES........................................................ 4
4.2.1
Mud Gas Separator .................................................................................... 4
4.2.2
Blowdown Line ........................................................................................... 5
4.3
HIGH PRESSURE KILL FACILITIES............................................................... 5
4.3.1
Kill Pump .................................................................................................... 5
4.3.2
Cement Unit ............................................................................................... 5
4.3.3
Kill Lines ..................................................................................................... 6
4.3.4
Bulk Transfer and Mixing System ............................................................... 6
4.3.5
Emergency Power ...................................................................................... 6
4.4
ADDITIONAL RIG INSTRUMENTATION......................................................... 7
4.4.1
Temperature Sensors ................................................................................. 7
4.4.2
Pressure Sensors ....................................................................................... 7
4.4.3
Pit Level Monitoring .................................................................................... 7
4.4.4
Remote Monitoring Facility ......................................................................... 8
4.5
4.5.1
CASING DESIGN............................................................................................. 8
Casing Setting Depth.................................................................................. 9
4.6
WELLHEADS AND XMAS TREES ................................................................ 10
4.7
WELL TESTING/COMPLETION DESIGN AND EQUIPMENT ....................... 12
4.7.1
Well Testing ............................................................................................. 14
4.7.2
Well Test Packer Fluid ............................................................................. 14
4.8
EQUIPMENT SELECTION/AVAILABILITY.................................................... 16
HPHT EQUIPMENT, DESIGN AND
MATERIALS
4.
Page 2 of 16
HPHT EQUIPMENT, DESIGN AND MATERIALS
It should be noted that issues highlighted for equipment, design and materials have a
strong link to IP 17 and generic industry practices.
4.1
BOP EQUIPMENT
It is of the utmost importance that the correct equipment is identified and selected
when drilling a high pressure, high temperature (HPHT) well. IP 17 highlights this under
Section 4 of the document and discusses specific requirements relating to Equipment
Standards, Inspection and Testing. This also links to the API Recommended Practices
53 and 16E. In particular, this should link firmly to the audit of the rig, to assess the
technical capability for an HPHT well. To summarise, the complete blowout preventer
(BOP) system is regarded as a safety critical piece of equipment, so the operator
should be able to identify and obtain good evidence of the maintenance and working
history of the equipment from the drilling contractor. This is part of the rig class
certification requirements and may also be covered by local legislation in various areas
around the world (eg verification requirements in UKCS).
4.1.1
BOP Equipment
BOP rams will be fitted with high temperature elastomers, having a continuous
working temperature rating of 250F and a peak working rating of 350F for one
hour peak service
All BOP components should be rated for H2S sour gas service, in accordance with
NACE MR0175-99. Shear ram blades must be of high strength, high hardness alloy
steel which is not necessarily limited to Rockwell Rc22. These alloys should be
certified for H2S service
If using variable bore rams (VBRs) within the BOP system, the temperature limits
for continuous and peak working should be assessed to ensure they are consistent
with the rest of the BOP system
4.1.2
Choke and Kill Lines
Choke and kill lines and their elastomers will be rated to the same pressure,
temperature and H2S sour service as the BOP rams
Flexible hose used in choke and kill lines, will be to the same pressure, temperature
and H2S service as the choke and kill lines. They should have a continuous working
temperature of 250F and a peak working rating of 350F for one hour peak service
HPHT EQUIPMENT, DESIGN AND
MATERIALS
4.1.3
Page 3 of 16
Choke Manifold
The choke manifold shall be fitted with a data monitoring system, which remotely
measures temperature and pressure downstream of the chokes. This information
should be available remotely at the Drillers’s console. Data from these instruments
should be used during well kill operations to ensure that the equipment is used
within its operating design limits. (Refer to IP 17 Section 4.2 Choke and Kill
Manifold)
Accurately calibrated digital pressure gauges should be installed on the standpipe
and choke manifold. These gauges should be used for well control operations
The following choke manifold valves should be remotely operated:
A valve upstream of each choke
Valve downstream of choke, which isolates the mud gas separator (MGS)
Overboard line valve
The choke manifold shall have the same pressure, temperature and H2S rating as
the BOP rams
Note: In the case of gas at surface, the Joule Thomson cooling effects (adiabatic
expansion) can reduce the temperature up and downstream of the choke
considerably. This not only affects the metallurgical properties of the equipment
but also creates problems due to hydrate formation.
Temperatures downstream of the choke can go as low as c. -100F due to the
expansion of pure methane, when controlling a gas kick from a high pressure
well. Therefore, equipment should be designed to cope with extreme low
temperatures as well as high pressures.
4.1.4
Hydrate Suppressant Injection Facilities
A hydrate suppressant injection system (glycol injection system) will be fitted upstream
of the choke (before gas is returned) to prevent hydrate formation. The suppressant
system shall have a minimum pressure rating equal to the BOP rams. The hydrant
suppressant system should be hooked up, tested and ready for immediate service.
Glycol can also be injected at the BOPs by pumping down the kill line, with either the
cement pump or dedicated kill pump. Adequate volumes of glycol should be calculated
to store on the drilling rig, injecting with the cement unit, or dedicated kill pump to
handle a major gas kick (this will be estimated and logged as part of the well control
bridging document).
The hydrant suppressant injection facilities would normally consist of two air driven
Haskell pumps, in parallel with stainless steel piping to the injection points, upstream of
the choke.
Note: Glycol is generally useful for controlling hydrates at temperatures above
c. -50F.
HPHT EQUIPMENT, DESIGN AND
MATERIALS
4.2
Page 4 of 16
SURFACE GAS HANDLING FACILITIES
The design and capability of the MGS will influence gas handling of a well control influx
at surface for a given gas handling capacity. IP 17 Section 4.3 highlights the main
issues and includes the handling capacity, instrumentation, hydrostatic mud seal and
bypass overboard lines.
However, the main issues for consideration are summarised below.
4.2.1
Mud Gas Separator
The drilling rig will be fitted with an MGS capable of handling large volumes of free
gas, which could be present when brought to surface in a well control incident. The
MGS needs to be sized to safely handle the maximum anticipated flowrate during
well kill operations
The liquid seal downstream of the MGS should be capable of typically maintaining a
positive seal of c.5.0psi against the MGS, while a fluid of 0.3psi/ft gradient is being
circulated through the system
The function of the MGS is to remove slugs of gas from the mud return line and
direct them through the derrick vent line. It is not designed to remove all of the gas
from the mud. This function is performed by the mud room vacuum degasser
The maximum gas handling capacity of the MGS will determine the maximum
allowable kill rate and requires assessment. This requires simulation to identify the
capacity to separate and vent the gas through the MGS during a well kill, without
blowing out the liquid seal for various pumping rates. If the maximum handling gas
capacity is reached during well control, the pump rate should be slowed down to
prevent blowing the liquid seal
The liquid seal will be dependent on the maximum operating pressure of the MGS.
The maximum operating pressure is dictated by the hydrostatic pressure of the fluid
in the liquid seal, via a dip tube. The density of the fluid in the liquid seal could vary
during a well control incident, due to the entrainment of gas, condensate, or oil in
the mud
To determine the maximum allowable operating pressure of the MGS, a pressure
sensor is installed at the base of the liquid seal. This pressure is displayed on the
drill floor near the remote choke control panel. Generally, the pressure in the MGS
should not exceed 80% of the liquid seal pressure. This value then acts as a datum
for calculating the maximum gas flowrate that can be safely handled from the MGS
performance graph
After determining the maximum allowable gas flowrate, the maximum circulating
rate that can be used for a given choke pressure can be read in from the graph,
showing values of gas production at various slow circulating rates (SCRs)
HPHT EQUIPMENT, DESIGN AND
MATERIALS
4.2.2
Page 5 of 16
Blowdown Line
There will be a blowdown line fitted downstream of the choke and prior to the MGS.
This is generally rated to 5,000psi and capable of a high gas flowrate, in the order
of c.50mmscf/day
The blowdown line will be used for the following circumstances:
If the pressure in the MGS cannot be maintained below the maximum allowable
If the line from the choke manifold to the MGS fails, or becomes blocked with
hydrates
4.3
HIGH PRESSURE KILL FACILITIES
4.3.1
Kill Pump
A high pressure, low volume kill pump (usually cement unit) rated to 15,000psi
working pressure will be fitted and incorporate 15,000psi fluid ends. At least one
fluid end shall be fitted with liners and pistons rated to 15,000psi, with additional
sets as backup
The kill pump should be capable of SCRs in the order of +/-0.5bbl/min
It should be independently driven and not rely on power from the installation
It may prove necessary to curtail operations if the kill pump is not operational during
the HPHT section of the well
The pump will be capable of being run at the unit, and remotely from the drill floor.
It will allow the well to be circulated, should rig power be lost
The accuracy of all pressure monitoring equipment for checking wellhead pressures
and pump pressures must be regularly checked and calibrated
Good communication links will be provided between the pump room and drill floor
4.3.2
Cement Unit
The cement unit will be rated to 15,000psi. Because of the low volume rates
required when cementing in the HPHT section, it may be necessary to dress both
fluid ends with 15,000psi liners and pistons
The unit will also incorporate low range pressure gauges for leak off tests (LOTs)
and an accurate pressure and pump volume recorder. Direct mud feed from the
active pit is required, to ensure accurate measurement of pit volumes during well
kill operations
The cement unit will normally be used to perform BOP pressure tests
HPHT EQUIPMENT, DESIGN AND
MATERIALS
Page 6 of 16
The high pressure lines from the cement unit to the rig floor must be pressure
tested to 15,000psi, prior to entering the HPHT section of the well
4.3.3
Kill Lines
A certified high pressure line from the kill pump to the rig floor with a circulating
head and flexible line, ready for quick make-up, should be available
High pressure kicks will utilise a 15,000psi kill assembly which incorporates a
drillpipe pup joint, full opening safety valve and side entry kill sub fitted with an HP
low torque hammer connection, to the high pressure kill line. The assembly should
be pressure tested, prior to entering the HPHT section of the well
4.3.4
Bulk Transfer and Mixing System
The bulk transfer and mixing system will be designed such that it can mix and
deliver the required kill mud at high speed, in order to perform the well kill
Bulk transfers of pre-mixed heavy mud should consider the maximum weight that
can be safely stored and transferred, taking into account the capabilities of all
pumps and hydrostatic pressures of the system
The weighting up rate, ie psi/ft per bbls/hr will be established, relative to the
capabilities of the bulk transfer and mud mix system (high rate barytes mixers)
4.3.5
Emergency Power
If the installation loses power during a well kill, the emergency generator will be
capable of supplying sufficient power to run the:
Main air compressor
Mud mix pump
Agitator
Fuel oil transfer pump
HPHT EQUIPMENT, DESIGN AND
MATERIALS
4.4
Page 7 of 16
ADDITIONAL RIG INSTRUMENTATION
Additional rig instrumentation should be made available on the rig to monitor critical
well parameters. This data will be displayed where it is visible from the remote choke
operating console.
4.4.1
Temperature sensors shall be placed at the following locations:
At the BOP and upstream of any coflexip hose
Upstream of the choke on both choke and kill lines
Buffer tank
Downstream of the choke
Mud in and out
Well test flowline upstream of all chokes
4.4.2
Temperature Sensors
Pressure Sensors
Pressure sensors shall be placed at the following locations:
Mud gas separator
Liquid seal hydrostatic head
Buffer tank
Upstream of the choke
Kill pump and mud pump
4.4.3
Pit Level Monitoring
The installation will have an accurate pit level monitoring system. For floating
operations, there will be a minimum of two pit sensors placed in all active pits.
Where a mud logging unit supplements the installation instrumentation, a
systematic cross check will be performed for both systems, in order that
discrepancies and datum calibrations can be established
All tanks including the settling pits should be monitored and will include a pit volume
totaliser
The trip tank will be monitored with an accurate volume sensor and will include an
additional independent means of measurement
HPHT EQUIPMENT, DESIGN AND
MATERIALS
4.4.4
Page 8 of 16
Remote Monitoring Facility
The kill pump (cement unit) will have a remote control facility at the drill floor (this will
enhance communications during the well control operations).
4.5
CASING DESIGN
A specific manual on casing design is available which discusses the principles of well
design and aspects associated with HPHT wells, under Section 9 of the manual.
However, it is worth highlighting key issues, which can affect the well planning process.
Due to the special requirements associated with HPHT wells, a full Triaxial VME (von
Mises Equivalent) analysis should always be performed as part of the well design. This
is important due to the large temperature effects on axial load profiles and combined
burst and compression loading. As a result of this approach, the design will be
performed by computer software and uniaxial hand calculations, to confirm the general
computer outputs of the software.
It is likely that a Senior Drilling Engineer, in conjunction with an independent internal
review and third party assessment, will design wells of this nature.
The main areas that require consideration are:
A full VME analysis for the well design, including all anticipated drilling,
testing/production loads
Well test philosophy utilising a kill weight, or underbalanced packer fluid (should
there be a need for a tie back)
Thermal effects and modelling for drilling and production loads, highlighting limits of
design (hottest from long-term production and coldest from scale squeezing)
Annular fluid expansion (AFE) effects and modelling, arising from closed annuli
(buckling and wellhead loading)
H2S and CO2 considerations, using the NACE document
Accurate assessment of pore and fracture gradient curves, including error bars and
probabilities of accuracy, for risk assessment
Accurate estimation of maximum pore pressure and reservoir composition at well
depth
Modelling of kick tolerances with mud systems (gas solubility in oil base fluids) for
estimation of maximum wellbore loads, due to the narrow margins, between pore
and fracture pressures
Reductions of tubular material yield strength, at high temperatures
Casing wear causing reduced mechanical strength of tubulars (see Section 2.5)
Tighter functional specification and inspection criteria, for tubulars and connectors
HPHT EQUIPMENT, DESIGN AND
MATERIALS
Page 9 of 16
Qualification testing of premium tubular connectors, to confirm axial and
compression capabilities
Assessment and analysis of the wellhead connector and riser system
(semi-submersible, IP Guidelines) as part of the well design pressure vessel
Assessment and analysis of wellhead system and conductor, as part of well design
pressure and thermal loads
Assessment and modelling of intermediate casing shoe depth and anticipated LOT
prior to drilling into the high pressure zone, as part of well design casing seat
selection
Note: Changing just one aspect of an HPHT well design, or load condition, can create
a significant overall change, due to the interaction of pressure and temperature.
Therefore, focusing on a tight specification and inspection criteria for the
tubulars and connectors, can reduce and minimise risk of failure during the
operational phase of the project. ie attempt to remove risk at the design phase.
4.5.1
Casing Setting Depth
For HPHT wells, casing seat selection is critical. A common design would be a 5 string
design, based on drilling 8-1/2 (8-3/8)in through the reservoir section, with the
contingency to drill 6 (5-7/8)in hole in the event of well problems, or increased
overbalance in the reservoir.
By way of example, we will consider the North Sea Central Graben Basin for a
well design.
The casing seat selection for HPHT wells is focused toward the intermediate string
(generally 13-3/8in) and the production string (generally 10-3/4in/9-7/8in) and should
be selected by consideration of the following issues:
The casing should be set at a minimum depth to ensure sufficient fracture gradient
(LOT) to provide adequate kick tolerance for drilling the reservoir
Maximum depth of Top Jurassic should be known, in order to determine the
minimum and maximum length for the high pressure transition zone, for selecting
the production casing shoe depth
The depth where the kick tolerance while drilling (hunting) for the production casing,
reduces to a predetermined unacceptable limit, should be known and not exceeded
In practice, the setting depth of the production casing depends on the pressure
transition zone at the base of the Cretaceous, which depends on the effectiveness of
the reservoir seal. The pressure transition can either occur rapidly, over a short interval
(c.100ft) or gradually, over a longer interval c.1,000 to 1,500ft.
HPHT EQUIPMENT, DESIGN AND
MATERIALS
Page 10 of 16
The intermediate casing (13-3/8in) must be set sufficiently deep to ensure that a high
mud weight can be used to allow the production casing to be set deep into the
transition zone. In practice, this means casing off the Paleocene sands and drilling
through the ‘dirty’ Ekofisk Chalk Formation until the clean Limestone of the Tor
Formation is penetrated for a certain distance, to obtain the required LOT. It is
important to design the well with this criteria, as the LOT at the 13-3/8in shoe drives the
well design and the number of casing strings required from this point.
The kick tolerance criteria for the intermediate string will probably require a ‘limited
kick’ design approach, (see Section 5 of the Casing Design Manual) as it may not be
able to satisfy the 100bbl gas kick criteria. This requires an iterative well design
assessment based on LOT sensitivities, as a function of the 12-1/4in hole depth. This
will normally be discussed and agreed as part of the well control ‘bridging document’.
Ideally, the production casing should be set as deep as possible into the base
Cretaceous, to obtain a higher LOT. This is due to the increasing pore pressure and to
case off potential sands/fractured zones. Where the pressure transition occurs over a
short interval, it may be possible to set the production casing deep (subject to the LOT
at the intermediate casing and the 12-1/4in hole condition). However, the production
casing may have to be committed high if permeable formations are penetrated below
the transition. This leaves a long 8-1/2/(8-3/8)in hole and increases the risk of
penetrating weak formations not capable of supporting the mud weight, required to drill
the reservoir. This may then require the 7in liner to be set early, as a drilling liner,
followed by the drilling of 6/(5-7/8)in hole through the reservoir to well depth.
4.6
WELLHEADS AND XMAS TREES
The design and assessment of wellheads and xmas trees demands the same depth of
rigorous review and specification, to satisfy the maximum anticipated loads and
operating envelope for all conditions during drilling, production and service.
Subassembly components of wellhead and tree systems that are most affected by
HPHT conditions are the non-metallic elements used for casing annulus, tubing hanger
and tree valve seals. Extreme temperatures subject almost all non-metals to premature
ageing and high pressures can lead to failure of these components by deterioration,
extrusion and explosive decompression. Wellhead and tree systems comprise many
components that require sealing interfaces between them. The sealing interfaces often
have non-metallic primary, or secondary components unsuitable for long term HPHT
production applications. All metal sealing systems eliminate the problems associated
with system degradation caused by deterioration of non-metal parts.
The key issues to consider for wellheads and xmas trees are:
Elastomers: High temperatures and pressures leading to premature ageing and
seal extrusion. API qualification tests have demonstrated that elastomer use is
limited to temperatures up to c.300F. If these are used on HPHT wells, evidence of
the capability for short and long-term use for safety critical components is required
HPHT EQUIPMENT, DESIGN AND
MATERIALS
Page 11 of 16
Metal-to-Metal Seals: Preferred sealing method for HPHT wells for all pipework,
tubulars, valves and safety critical systems. They may incorporate a combination of
resilient elastomers as backup to the primary metal sealing system
Performance Testing: API has established minimum requirements for performance
testing of wellheads and production xmas trees. API Specification 6A Wellhead and
Xmas Tree Equipment defines the pressure, temperature and fluid compatibility
classes for wellhead equipment. Pressure classes range from 2,000 to 15,000psi,
temperature classes range from 75 to 350F and fluid compatibility classes range
from sweet to sour service. HPHT operational temperatures of 400 F exceed the 6A
specification temperature classification and require additional procedures to qualify
equipment for HPHT service
Xmas tree valves are fire tested as specified in API Specification 6FA, Fire Test for
Valves. Tree valves are pressurised to 75% of design pressure and subjected to
o
2,000 F for 30 minutes to simulate a platform fire. The valves are expected to
contain their pressurised internal fluid, without significant leakage during and after
the fire and operate without leaking after the fire is extinguished. Wellhead and
xmas tree connections are qualified to the requirements of API Specification 6FB,
Fire Test for End Connections
Laboratory Test Results: This provides the opportunity to verify the API
specifications through qualification testing based on specific temperature and
pressure limits
For example, this requires performance testing key components within the wellhead
and xmas tree systems for HPHT service, as specified by API Specification 6A. This
may require a range to 400F to simulate anticipated production temperatures, in
conjunction with fire resistance testing. Typically, this requires performing the tests at
the anticipated extreme range of temperatures and pressures.
Other issues to consider for the functional specification and qualification testing
may be:
The required Product Specification Level (PSL) specification, eg build to PSL 3 but
with PSL 4 gas testing (API Spec 6A)
Sand Trim requirements (API Spec 14D)
Well life cycle issues such as trapped fluid pressures on initiation of production, or
if the system was on fire
Wire cutting capability of valves
Cumulative stress cycles, leading to cyclic fatigue (as part of Finite Element
Analysis, FEA)
Compatibility with well fluids (hydrocarbons, CO2 and H2S)
Lock down design for wellhead housings and hangers
HPHT EQUIPMENT, DESIGN AND
MATERIALS
Minimum number of wellhead penetrations
Uniform stress distribution for critical components
4.7
Page 12 of 16
WELL TESTING/COMPLETION DESIGN AND EQUIPMENT
Well testing and completion design should be treated as part of the HPHT project in
the same way as casing design. Due to the special requirements associated with
HPHT wells, a full Triaxial (von Mises Equivalent) analysis should always be performed
as part of the design process. This is required due to the various effects of the
combined loads and high pressures and temperatures. As a result, designs will be
performed by computer software and uniaxial hand calculations, to confirm the
computer outputs.
It is likely that a Senior Petroleum Well Test and Completion Engineer, in conjunction
with equipment vendors and an independent third party, will design the drill stem
testing (DST)/completion.
One of the key issues to note is the well test/completion design and assessment of
equipment must not be performed in isolation. It is important that the issues of concern
are discussed and planned at an early stage, as part of the well design process. Often
on standard wells the decision to perform a well test (and planning) is left until near the
end of the drilling of the well. HPHT projects do not allow this type of approach to be
used.
The main areas that require consideration are:
A full VME analysis for the well design, including all anticipated, testing/production
loads based on worst case scenarios
Well test philosophy utilising a kill weight, or underbalanced packer fluid (should
there be a need for a tieback)
Pressure test programme for the wellbore, prior to displacing to an underbalanced
packer fluid
Performing a risk analysis and hazard identification for all operations, associated
with the DST/completion
Use of a completion type design as a DST string
Redundancy and contingencies for equipment (eg multiple data acquisition gauge
carrier systems)
Optimising minimum production casing/liner size for productivity, well test and
completion objectives. (Maximum size of: perforating guns, subsurface safety
valves and packers)
Chemical composition of completion fluids relative to formation pressure and
degradation of seals and tubulars
HPHT EQUIPMENT, DESIGN AND
MATERIALS
Page 13 of 16
Assessment and use of control line fluids for DST/completion surface controlled
subsurface safety valves (SCSSSVs) for HPHT conditions
Thermal effects and modelling for all testing and production loads, highlighting
limits of design (hottest from long-term production and coldest from scale
squeezing)
Annular Fluid Expansion effects and modelling, arising from closed annuli (buckling
and wellhead loading)
H2S and CO2 considerations, highlighting limitations on various tubulars, using the
NACE document
Assessment of sand production (erosion), water production (corrosion, CO2)
Assessment of perforation techniques and explosives as a function of exposure
time and downhole temperature
Accurate assessment of bottom hole pressure, including error bars and accuracy,
for risk assessment
Linking well test objectives to the data obtained during drilling, by formation
evaluation techniques (MWD, LWD, coring, wireline logs, RFT, MDT etc)
Accurate estimation of maximum pore pressure, temperature and reservoir
composition at reservoir well depth
Modelling of production flowrates relative to pressure and temperature, for
estimation of maximum wellbore loads and formation of hydrates
Assessment and use of DST/completion packers. Capability of fixed versus
retrievable packers
Reductions of tubular material yield strength, at high temperatures, including
corrosion resistant alloys
Tighter functional specification and inspection criteria, for tubulars, connectors,
surface DST packages and all downhole equipment
Qualification testing of premium tubular connectors, to confirm axial and
compression capabilities
Simplifying use and choice of seals for DST/completion design, to maximise use of
metal seal technology and high temperature elastomeric seals. (Linking seal
requirements for downhole and surface equipment by use of proven technology and
evidence of qualification testing)
Assessment and analysis of the wellhead connector and riser system,
(semi-submersible IP Guidelines) as part of well design operating envelope, for
shut down of testing and emergency disconnect
HPHT EQUIPMENT, DESIGN AND
MATERIALS
Page 14 of 16
Assessment and analysis of wellhead system and xmas tree, as part of well design
pressure and thermal loads
Design, layout and hazard assessment of DST surface equipment including
emergency shutdown (ESD) systems, with the drilling contractor at an early stage
(link to initial rig audit at pre-tender stage, to identify capabilities of rig)
Design DST and completion operations to minimise wireline operations and
downhole accessories (wellbore safety and reliability)
Requirement and assessment of cement evaluation tools for well integrity and
perforating of reservoir (CBL/VDL/USIT/CET type tools)
4.7.1
Well Testing
Well test and completion design will typically include the following load cases and
tubing stress calculations, taking into account maximum and minimum
temperatures/pressures:
Tubing pressure test
Maximum well flow
Surface shut-in
Downhole shut-in
Tubing leak
Bullhead for well kill
Pressure test below packer
4.7.2
Well Test Packer Fluid
Probably the single biggest issue for HPHT DST and completion design is the choice
for using, either a weighted, or underbalanced packer fluid.
Using a DST as a design basis, the choice of packer fluid has a significant impact on
the well test programme, equipment, operations and capability of the casing design.
For example, if an overbalanced mud is used as the DST packer fluid, the production
casing design (10-3/4 x 9-7/8in) will not be able to withstand the most dominant load;
that of a tubing leak at surface, on top of the packer fluid. The differential burst
(external – internal pressures), at the base of the production casing, would not be
capable of coping with this specific load case.
This can be overcome by installing a tieback string which protects the production
casing but also introduces new complexities, such as trapped annular expansion
forces, minimum clearance diameters for the test string and additional time/cost to
the project.
HPHT EQUIPMENT, DESIGN AND
MATERIALS
Page 15 of 16
The decision of an overbalanced kill fluid versus an underbalanced fluid requires
detailed assessment and risk analysis for both methods; highlighting the positive and
negative aspects of each system. However, there is now much more widespread use of
water as a packer fluid and industry has built up a detailed database of its use,
including benefits, problems and incidents.
The choice of the fluid has a direct impact on the perforation method, test string design,
testing procedures, well kill and safety of personnel and drilling rig.
The following lists summarise some of the advantages and disadvantages for
each system:
Kill Weight Fluid
Advantages:
Safety: hydrostatic kill fluid
Reduced differential pressure across the packer element and seal assembly
Reduced differential pressure for DST tools
Disadvantages:
Poor reliability of DST tools (pressure transmission, plugging of pressure ports)
Rheology of mud (gels, barytes settling)
Minimal clearances/high surge pressures whilst running plugs, packers
Difficulties for setting TCP firing head pressure shear values
Difficulties in performing wireline operations
Casing design complexities. Tubing leak at surface requiring a tie-back, trapped
annular fluid pressures
Underbalanced Fluid
Advantages:
Casing design. Can remove the requirement for a tieback, reduces differential burst
pressures for production casing, and provides greater annular clearance for test
string design
Provides solids free and clean downhole environment for equipment
Improved reliability and functioning of downhole test tools
Ease of circulation and reduced frictional pressures for test string
Quality pressure tests of downhole equipment and wellbore
HPHT EQUIPMENT, DESIGN AND
MATERIALS
Page 16 of 16
Wireline operation capability improvements
Reduced surface temperatures while flowing due to higher conductivity of water
over mud
Disadvantages:
Safety: Not a well kill fluid
Consequence of high pressure at wellhead, from leak at packer
Higher differential pressure across packer element and seal assembly
Higher differential pressure for DST tools
Adequate barriers in place for emergency disconnect (no kill fluid in annulus)
Casing Design: Requirement to thoroughly inflow test wellbore and liner lap, prior to
finally pulling out of hole
Well kill: longer and possibly more complex
Gas migration can take place in the annulus at a much higher rate
Drilling rig BOP system and equipment must be able to achieve a full recovery of
well, with the drillstring out of the hole, if wellbore integrity fails (ie leak at liner lap
requiring a full strip-in to the bottom of the wellbore to perform a well kill)
It would be normal practice to assess all of the above issues as part of a detailed
hazard and operability study (HAZOP). However, the impact of the DST/completion
design on the overall well design, requires early assessment.
4.8
EQUIPMENT SELECTION/AVAILABILITY
Selection and timely availability of equipment are key factors in the success of HPHT
wells. In planning HPHT wells, the long lead times and stringent QA requirements for
critical equipment such as casing, tubing, wellheads and completion equipment need to
be taken into account. Failure to do so can result in well delays, design compromises
and significant additional costs.
Procurement strategies for equipment need to be formulated well in advance. In some
cases, equipment rental may be advantageous. Equipment backup and the availability
of contingency stocks (eg casing for a relief well) also need to be considered in the
design, assessment and planning phase. Standardisation and equipment sharing
between Assets should be encouraged. The longest lead items are generally for casing
and tubing, wellhead, xmas trees and completion equipment These items are also the
most critical in terms of performance and cost and require detailed early planning.
Finally, requests for additions and tests to the functional specification, such as
qualification testing, will add time and cost.
SECTION 5
Drilling and Production Operations
Ref: HPHT 05
SPECIAL WELLS MANUAL, VOLUME I:
HIGH PRESSURE, HIGH TEMPERATURE
Issue: Feb 2000
DRILLING ENGINEERING
CONSIDERATIONS
Page 1 of 28
TABLE OF CONTENTS
5.
DRILLING ENGINEERING CONSIDERATIONS.................................................... 3
5.1
ESTIMATION OF PORE PRESSURE AND FRACTURE PRESSURE............. 3
5.1.1
Pore Pressure Prediction............................................................................ 3
5.1.1.1
Empirical Methods of Prediction................................................................. 4
5.1.1.2
Modelling Tools.......................................................................................... 5
5.1.2
5.2
Fracture Pressure Prediction and LOT Data............................................... 6
DRILLING FLUIDS........................................................................................... 7
5.2.1
Types of Systems ....................................................................................... 7
5.2.1.1
5.2.1.2
5.2.2
Oil Based Muds ......................................................................................... 7
Water Based Muds .................................................................................... 8
Drilling Fluid Planning and Operations ........................................................ 9
5.2.2.1
Planning..................................................................................................... 9
5.2.2.2
Operations ............................................................................................... 10
5.2.2.3
Drilling Fluids: Well Control...................................................................... 11
5.3
CASING RUNNING OPERATIONS................................................................ 11
5.3.1
5.4
Equipment Selection................................................................................. 12
CEMENTING OPERATIONS ......................................................................... 13
5.4.1
Equipment ................................................................................................ 13
5.4.2
Slurry Designs .......................................................................................... 14
5.4.2.1
Slurry Testing........................................................................................... 14
5.4.3
Spacers .................................................................................................... 17
5.4.4
Simulations............................................................................................... 17
5.4.5
Temperature Estimation ........................................................................... 18
5.4.6
Contingency Planning............................................................................... 18
5.5
TEMPERATURE PROFILES.......................................................................... 19
5.5.1
Temperature Hazards............................................................................... 19
5.5.2
Temperature Sources ............................................................................... 20
5.5.3
Modelling Temperature Profiles ................................................................ 20
DRILLING ENGINEERING
CONSIDERATIONS
5.6
Page 2 of 28
WELLBORE EVALUATION ........................................................................... 21
5.6.1
Formation Evaluation................................................................................ 21
5.6.2
Casing/Cement Integrity Monitoring.......................................................... 24
5.7
IDENTIFICATION OF TRANSITION ZONE ................................................... 24
5.8
SLIMHOLE DRILLING ................................................................................... 25
5.9
WELL MANAGEMENT .................................................................................. 26
5.10
EMERGING TECHNOLOGY.......................................................................... 27
5.10.1
Expandable Solid Tubular Technology ................................................... 27
5.10.2
Mud Pulse Telemetry ............................................................................. 28
5.10.3
Coil Tubing Perforating .......................................................................... 28
DRILLING ENGINEERING
CONSIDERATIONS
5.
Page 3 of 28
DRILLING ENGINEERING CONSIDERATIONS
This section emphasises the importance of carrying out detailed pre-planning to
minimise the uncertainties, reduce risk, ensure safety and remove potential problems
at the design stage, with a dedicated multi-discipline team. Spending time to define the
well objectives and well type will benefit the project during the operational phase. For
example, if the high pressure, high temperature (HPHT) well is a vertical exploration
with a short-term well test, then the design and thermal modelling will not be as
complex, compared to a well that experiences long-term production loads.
5.1
ESTIMATION OF PORE PRESSURE AND FRACTURE PRESSURE
One of the key areas of HPHT well planning is a detailed analysis and use of the
subsurface geological uncertainties and drilling data, in order to generate realistic pore
and fracture pressures for the well. There are various methods and techniques for
estimating the pore and fracture data. Additionally, offset data and regional basin
studies, should form part of the initial preparation for a HPHT project.
Once these have been assessed and used to obtain a profile, statistical techniques
and confidence levels may also be employed to perhaps define a minimum and
maximum range. However, once all of the data has been assessed, it is recommended
that a realistic pore and fracture gradient plot be constructed, in order that all team
members are planning the well with the same information. It is important to recognise
that the pore pressure is the result of a number of different methods and the main pore
pressure/fracture pressure prediction process may change with depth.
5.1.1
Pore Pressure Prediction
The burial history of a sedimentary column with a given composition and heterogeneity
will determine its framework strength and the pressure and temperature of the fluids in
the pore space at any depth. Both the burial history and the composition of the
sedimentary column are subject to uncertainty. Indirect data may be used to constrain
these uncertainties and define most likely values for a given depth, including minimum
and maximum values.
The reliable estimate of a permeable formation pore pressure is provided by a repeat
formation test (RFT) type test/measured data. Similarly, formation strength can only be
accurately estimated from an extended microfrac test. Any other indirect assessment of
pressure, or strength is subject to uncertainty until calibrated. These uncertainties will
vary with methods, or data used and need to be carefully evaluated.
Page 4 of 28
DRILLING ENGINEERING
CONSIDERATIONS
In the prognosis of pressures it is essential to carry out a proper analysis, paying
attention to interdependencies of the various parameters. For instance, compounding
of worst case scenarios (eg shallow reservoir, highest possible overpressure and
longest possible hydrocarbon column) will result in either an undrillable well, or in a
very dangerous situation due to a severe overbalance. A multi-disciplinary teamwork
approach between the geoscientists, petroleum/reservoir and the drilling engineer,
should promote risk management, minimise risk and result in a realistic
pressure profile.
There are no hard and fast rules for the prediction of rock strength, fluid pressure or
temperature. All techniques rely to a large extent on empirical relationships, or require
assumptions of rock property parameters that are not routinely available by direct
measurement. A detailed analysis of the data is, therefore, important.
5.1.1.1
Empirical Methods of Prediction
This is by far the most common practice to date. It essentially means careful analysis
of all pressure and strength data in an area, in order to deduce predictive relationships
of pore pressure and formation strength with depth. The following issues should be
considered:
Basin fill history (tectonic setting, sedimentation rates, vertical/lateral permeability
contrasts)
Temperature history (heat flow, maturation)
Hydrocarbon habitat (generation, expulsion, migration)
Regional temperature/depth relation (drill stem test (DST), corrected RFT, corrected
bottom hole temperature (BHT))
Regional rock strength/depth relation (leak off test (LOT) data, minifrac data,
mudlog records, regional stress field)
Indirect pore pressure estimates: trip connection gas, wellbore instability such
as cavings
Regional pressure/depth relation (mud weights, RFT, DST, gains/losses)
Depth of onset of overpressures (shallowest possible from seismic)
Thickness of transition zone (likelihood of stacked pressure cells)
Hydrocarbon effects
column lengths)
A real distribution of overpressures (pressure cells, sealing faults)
Borehole breakout direction for regional fault studies and wireline logs from wells
(composition,
pressure
gradients,
and
maximum
They highlight the importance of maintaining a quality database, for all indicators of
pore pressure and formation strength.
DRILLING ENGINEERING
CONSIDERATIONS
5.1.1.2
Page 5 of 28
Modelling Tools
All of the following methods should be used with respect by researching the data from
a wide variety of sources.
These are essentially based on calibrated, semi-empirical functions. Examples are the
d-exponent data from offset wells, Eaton's method, Eaton Modified, Hottman and
Johnson’s method, etc. All these algorithms attempt to predict pressure and strength
via effective stress porosity relations from sonic and resistivity logs; careful
calibration with RFT and minifrac data is, however, necessary. These methods are
essentially hindsight methods. Application of MWD/FEWD and real-time processing
techniques are also available, which can help modify the pressure prediction whilst
drilling.
The following are examples taken from an extensive body of literature, on the subject of
pore and fracture pressure modelling:
Another method discussed by Bowers, GL: Pore Pressure Estimation from Velocity
Data: Accounting for Overpressure Mechanisms Besides Undercompaction
(SPE 27488) discusses a new method, that utilises virgin and unloading curve
relations, to account for both undercompaction and fluid expansion overpressure. A
Central North Sea example is included and compares the estimated pressures with
mud weights used during drilling and RFT data. It can be seen that outside the chalk,
the pore pressure estimates are in good agreement with the measured values.
However, within the chalk, as was discussed within the paper, the predictions are
essentially a guess. Some of the conclusions within the paper are Failure to account
for the absence or presence of fluid expansion overpressure can lead to large errors in
the estimated pore pressure. Therefore, it is important to have a systematic approach
for estimating pore pressure due to both undercompaction and fluid expansion. Such
an approach has been presented. It consists of two key elements: 1) a pair of velocity
versus effective-stress relations that account for overpressure mechanisms besides
undercompaction, and 2) a procedure for determining when each relation should be
used. Both elements are equally important.
Another SPE Paper 28297 (Ward CD, Coghill K, Broussard, MD) The Application of
Petrophysical Data to Improve Pore and Fracture Pressure Determination in North Sea
Central Graben HPHT Wells, discusses pore pressure estimation methods, based on a
shale disequilibrium compaction model and proposes that excellent results can be
obtained by deriving porosity from density, or deep resistivity data. This porosity,
together with a lithology estimation from the gamma ray, are input into an effective
stress loading limb (ESL) model that calculates pore and fracture pressures through all
major lithologies.
Basin modelling tools can also be used to predict (largely qualitative) pressures. The
advantage is if a source rock is identified which is currently generating gas; it can be
inferred that this interval has a potential for overpressure, generated by fluid expansion.
In individual regional areas there may be a dominant and preferred pore pressure and
fracture pressure evaluation technique. The reader is advised to deploy this if there is a
local reason for so doing.
DRILLING ENGINEERING
CONSIDERATIONS
5.1.2
Page 6 of 28
Fracture Pressure Prediction and LOT Data
Proper care has to be taken to correct measured temperatures where necessary and to
evaluate the formation strength relationship with depth and lithology. Careful analysis
of leak off test data and drilling records (losses) in nearby wells can establish a relation
between fracture propagation pressure and depth. In the absence of tensile rock
strength and tectonic stresses, the leak off test is a measure of the minimum horizontal
stress. This in turn will be a measure of the maximum possible fluid pressure, which
would reduce the effective stress to zero.
Due to the correlation between fluid pressure and formation strength via effective
stress (effective stress is the fracture pressure, minus the pore pressure), the LOT
database should make a distinction between normal and overpressured wells.
Regional trends should be carefully evaluated and an assessment should be made on
how applicable they are to the well under consideration (eg local tectonic stresses).
An SPE Paper 28710 ‘A Simple Method to Estimate Fracture Pressure Gradient’ by
Rocha LA, Bourgoyne AT, discusses the issues associated with estimating fracture
pressure gradient. The proposed method has the advantage of: 1) using only the
knowledge of leak off test data and 2) being independent of the pore pressure.
Holbrook P, SPE Drilling and Completion, March 1997 ‘Discussion of A New Simple
Method to Estimate Fracture Pressure Gradients’, discusses the accuracy of both the
Terghazi effective stress law and the Rocha and Bourgoyne fracture pressure method
(SPE Paper 28710). This examines their individual linkage to mechanical first
principles, stress and strain definitions. These definitions are linked with two
fundamental stress/strain relationships applicable to porous granular solids in biaxial
normal fault regime basins.
Failure to thoroughly analyse the fracture strength of formations can lead to formation
breakdown during well control, as outlined in SPE Paper 38478 by Element DJ, van der
Vossen, Diamond S, Hamilton TAP ‘Consequences of Formation Breakdown During
Well Control: A Study of Underground Crossflow While Drilling an HPHT Well’. This
discusses the underground flow between the kicking formation and a loss zone.
Almost all modelling methods assume overpressure is directly related to anomalous
claystone porosity. This does not work for the case of fluid expansion overpressure
methods. With fluid expansion the critical factor is the seal strength. This can be with a
strong seal that gives rise to a very rapid overpressure, for a short length in the
transition zone.
DRILLING ENGINEERING
CONSIDERATIONS
5.2
Page 7 of 28
DRILLING FLUIDS
The wellbore fluid utilised for an HPHT well plays an important critical role in terms of
the drilling, wellbore integrity and maintenance for the life of the well. This is due to not
only the narrow safety margins between the pore/fracture gradients but also the very
high temperatures and a third equally important variable, time spent within the well.
Therefore, in terms of designing and maintaining an HPHT fluid system, the statement
should really read as: HPHT/T (high pressure, high temperature and time).
The key parameter for any fluid system used on an HPHT well is: ‘stability’ at elevated
pressures and temperatures over a defined time period.
The small difference between the pore and fracture pressures in the overpressured
HPHT section requires a drilling fluid system with a stable and robust rheology that
minimises equivalent circulating densities (ECDs), losses and maintains the required
overbalance, to reduce the risk of a well control incident.
The issues addressed in this document for drilling fluids, apply equally to the
completion and workover fluids, except for exposure to the geological formations.
5.2.1
Types of Systems
There are two generic systems to consider for HPHT wells:
Oil based muds (OBMs) and water based muds (WBMs). Both have their respective
positive and negative points to consider.
5.2.1.1
Oil Based Muds
These cover a wide range of systems that have evolved over a number of years, to the
current most widely used synthetic oil based muds (SOBMs). Other systems that have
been developed include esters (which are less stable at high temperatures) and low
toxic oil based muds (LTOBMs - which can be problematic under HPHT conditions, due
to the viscosity of the base oil).
The reader also needs to be aware that many areas around the world do not allow
unrestricted cuttings discharge with a SOBM. This influences the choice of drilling fluid
and the logistics/treatment of the cuttings, as many areas is now moving toward a
restricted discharge policy.
It is quite common for an HPHT well to utilise WBMs for the top half of the well and
then switch over to OBMs for the latter, deeper, hotter, higher pressure regimes. This is
because WBMs are sensitive to temperature and the SOBMs are inherently more
stable for longer, at higher temperatures.
DRILLING ENGINEERING
CONSIDERATIONS
Page 8 of 28
Other benefits of using an SOBM are:
Good lubricity
Formulated to minimise sag
Ability to achieve more desirable YP/PV ratios, resulting in lower ECDs (YP/PV > 1)
Formation protection – Low fluid loss, all oil filtrate, no swelling of clays
Control of fine solids less problematic at high mud densities
Issues requiring consideration for using a SOBM are:
Surfactants in emulsifiers may cause formation damage
Rheology and density of SOBMs are sensitive to temperature and pressure
Requires corrections to the surface measured mud weight, for downhole conditions
Environmental or logistical considerations may severely restrict, or prohibit their use
Flash point of the SOBM base oil, relative to the maximum anticipated flowline
temperatures while drilling
5.2.1.2
Water Based Muds
A typical WBM formulated system for an HPHT well may be based on a
bentonite/synthetic filtration polymer, with lime to treat out the carbonates from the
barytes impurities.
The benefits of using a WBM can be summarised as follows:
Less problems associated with environmental legislation for drilling in sensitive
areas
Formulated to prevent sag
Can be formulated for stability, for an estimated temperature and pressure
Can achieve low ECDs, if the rheology is maintained for a stable environment
Can be considered for reservoir protection
Issues requiring consideration for using a WBM are:
Not as stable as an SOBM under the same HPHT conditions. WBM polymers can
break down at high temperatures and thus can be more difficult to control and
maintain. (SOBM are more stable and simpler to maintain, hence more reliable
for drilling)
Requires additives to improve lubricity
DRILLING ENGINEERING
CONSIDERATIONS
Page 9 of 28
May not be suitable for water sensitive reservoirs
Concern regards long-term robustness and stability, compared to an SOBM (from a
production point of view)
5.2.2
Drilling Fluid Planning and Operations
There are a number of areas to consider for drilling fluids during the planning and
drilling of the well. Effort and time spent in assessing and identifying a suitable system
at an early stage, will prove beneficial during the operational phase of the well.
5.2.2.1
Planning
The following points should be resolved at an early stage of the HPHT project,
assuming an SOBM system is used. (This is based on a conceptual casing design
being in place, with a clear policy on the use of either a weighted, or un-weighted
packer fluid for DST/completion purposes.):
Track record of HPHT wells drilled to date (exploration and development)
Detailed laboratory tests, (including hot rolling and thermal modelling), as part of
the well design. The casing design thermal modelling requires the mud system and
properties to be identified, in order to estimate the maximum flowline temperatures
for each hole size. This is then fed back to the fluids company, to validate the
performance of the mud system for maximum conditions
Stability tests for various system formulations, to determine long-term stability and
robustness, including well control simulations
Rheology modelling for the identified hole sizes and BHAs to determine flowrates,
ECDs, swab/surge pressures, optimum PV/YP and gels
Well simulations using a rheology model that is integrated with an advanced
pressure and temperature simulator. This should include rheology measurements
under downhole Fann 70 conditions, as the data is used to predict accurate ECDs
and ESDs (Equivalent Static Density)
Testing stability and rheology of the system at high deviations for development
wells
DRILLING ENGINEERING
CONSIDERATIONS
5.2.2.2
Page 10 of 28
Operations
The following subjects are listed as issues to consider during the operational drilling
phase of an HPHT well. This assumes the system is an SOBM.
Use of an HPHT pressurised mud balance to measure the mud properties relative
to downhole conditions
Measurement of the mud density at a 120F reference temperature. This is used
because it represents a practical value of the average circulating temperature for a
mud system. Estimation of the correct mud weight at temperature can be achieved,
by using data supplied by the fluids company
Mud property modification requires careful planning. Two examples are: Shearing
the mud system properties within the casing, prior to drill-out and restricting direct
chemical additions to the active system while drilling
Efforts to keep the mud weight as low as possible while maintaining an
overbalance, during the drilling of the high pressure zones, with narrow pore and
fracture margins
Flowline temperature control through mud flowrate adjustment: Monitoring of mud
returns at the flowline as a function of flowrates to establish the limits on equipment
and the flash point of the SOBM. Small reductions in flowrate can be sufficient to
bring down the flowline temperature. (This would have been assessed during the
planning phase, as part of the wellbore thermal modelling and assessment of hole
cleaning efficiency)
Measurement of gains and losses in the circulating system at surface in the mud
pits, due to the expansion and cooling effects of the SOBM. The fluids company
should have software for this analysis, and its use should be incorporated as part of
the drilling fluid checks
Downhole rheology behaviour of the mud system should be monitored frequently,
utilising the Fann 70 viscometer. Data from this analysis can be used to assist in
the prediction of ECD and ESD
Conducting swab and surge pressure tests in cased hole, prior to drilling out the
casing to act as a reference while drilling the section
Prior to pulling out of hole (POOH), the string should be pulled wet to obtain
information regarding the behaviour of the hole/formations and at the same time to
avoid disturbing the well by pumping a slug. Particular attention should be paid to
selecting the correct tripping speed, which will vary with bit depth. Pumping while
pulling out of hole can prevent the bottom hole pressure from falling below static
pressure due to swabbing effects
Running into the hole with the pumps on can cause significant surge pressures.
This is most important when considering washing down to bottom before drilling,
running to bottom with pumps on after a connection and when reaming into the hole
DRILLING ENGINEERING
CONSIDERATIONS
5.2.2.3
Page 11 of 28
Drilling Fluids: Well Control
The choice of drilling fluid for an HPHT well can impact the control of a well incident.
Some of the differences to note for SOBM and WBM systems are:
a. SOBM
A flow check in SOBM may require longer to assess a potential influx, due to
temperature induced volume changes
The influx stays in solution and can mask the kick. As a result, the final influx
volume may be larger before it is recognised
If the well is shut in for a long period, the influx may stay in suspension for
longer with less migration, than a WBM system
The influx can spread out within the annulus while performing the well kill,
resulting in more manageable volumes to process and easier handling
capacities for the MGS. This can result in slightly lower pressures than a WBM
Note: An SOBM system is generally regarded as a more desirable system for HPHT
well control purposes.
b. WBM
Influx does not stay in solution, so can migrate to surface
Influx stays in place as a cohesive volume, thus producing higher peak
pressures and larger volumes for the MGS to handle at surface
All of the above issues should be addressed by performing well control simulations, as
part of the well control bridging document, in conjunction with the drilling contractor.
5.3
CASING RUNNING OPERATIONS
The casing running operations for HPHT wells require assessment at the well design
stage. This is due to the weight of the casing strings, the casing axial loads and to
confirm the capability of the drilling rig (mast, substructure, travelling block,
compensator if the rig is a semi and rating of drawworks). Preliminary casing weights
should be identified as part of the initial rig pre-tender audit, to check the capability of
the drilling rig. Involvement of the drilling contractor at an early stage will ensure that
the team defines the safest, optimum method of casing running.
The well design should assess the minimum and maximum mud weights, together with
the risk of lost circulation (loss of buoyancy leading to higher axial loads). The method
of pressure testing the casing will also have an impact on the equipment required for
the casing string, relative to the pressure components of the drilling rig (eg full pressure
test as part of cementation, or after waiting on cement).
DRILLING ENGINEERING
CONSIDERATIONS
Page 12 of 28
If the maximum axial Von Mises Ellipse (VME) and minimum API load capacity is close
to the limits of the operating envelope of the connector and pipe, a revised method of
casing running may be required to limit the axial load. For example, not filling the pipe
completely to a predetermined level and floating the casing into the well.
5.3.1
Equipment Selection
All casing tools and equipment should be identified, inspected and assessed with the
drilling contractor and casing running company for anticipated maximum load
conditions. The assessment should identify the weakest component in the system and
the sizing and fitting to the top drive (eg water bushings and crossovers for well control,
limitations of elevators: 500 or 750 ton, compatibility of elevator links, circulating
swage).
The drilling line may also need to be strung with additional lines to cope with the
increased load. This has an impact on the casing running speed (slower) and should
be used to estimate the total time required for the job, from the pick up of the first joint,
to landing and final cementing (relevant for a semi-submersible weather prediction and
emergency hang-off).
Additionally, if using a semi-submersible, the compensator may need to be locked due
to limitations on its maximum rating.
Casing slip type elevators should be assessed to determine sizing, tolerances and to
ensure the elevator slip point contact area does not create concentrated stresses,
through the system onto the pipe. This could introduce localised yield hardening
making the casing more susceptible to stress corrosion cracking, if exposed to sour
well fluids.
The strength and handling of the landing string will depend on the cementing system
adopted: full-bore surface launch, or high strength drillpipe with a subsea launch
system.
All equipment should be checked for dimensional accuracy and fit. Important if using
non-standard API oversize casing and also for combination strings such as 10-3/4in x
9-7/8in.
The complete process of casing running operations and equipment selection for deep,
heavy HPHT wells requires a thorough assessment including, detailed involvement of
the drilling contractor and the casing running company.
DRILLING ENGINEERING
CONSIDERATIONS
5.4
Page 13 of 28
CEMENTING OPERATIONS
The design and planning for HPHT cementation operations require higher levels of
technical resource over and above the criteria for a standard well. It is important to
appreciate that all of the cementing requirements should be a seamless part of the well
design, at an early stage of the project. This section focuses on the equipment, slurry
design, spacers, simulations and contingency planning, for HPHT wells.
Cements for HPHT applications should be good quality API Class G or H with an
emphasis on quality and consistency. For deeper sections of the well, it is normal
practice to use high content levels of Silica Flour to cope with the higher temperatures.
An example of the planning required is selection of the final liner size eg 5in in 6in hole,
or 5in in 5-7/8in hole, or 4-1/2in in 5-7/8in hole.
The preliminary design and drift sizes may indicate a 5-7/8in bit is required to pass
through the 7in drilling/production liner. However, cementing hydraulic simulations will
probably fail using a 5in liner, resulting in the need to change to a 4-1/2in liner. This
has an immediate impact in well testing access for DST tools and productivity of the
well. Hence the need to resolve cementation issues early at a conceptual stage.
5.4.1
Equipment
The following equipment issues should be taken into consideration on HPHT wells:
Specification and selection of float equipment, including the plugs. In particular,
temperature and pressure rating of the components of the production string. This is
critical if planning to conduct the full casing pressure test, immediately after cement
plug bump
Length of casing shoe tracks. Important due to the risk of contamination at the
casing shoe, for the combination production casing (10-3/4 to 9-7/8in) and the
impact of small volumes on liners. It is not unusual to utilise a significant shoe track
length (240 to 400ft) on the combination production casing, to reduce risk of
contamination and over displacement
Centralisation, in terms of achieving the minimum standoff and identifying planned
top of cements
If offshore, assessments of surface launch versus a subsea launch plug system.
This will also be linked to the method of installing the wellhead casing seal
assembly
Identifying adequate HPHT cement heads and swedges, including inspection, work
history and QA/QC of components for high pressure use
Identifying liner hanger systems in terms of mechanical strength and sealing ability,
eg mechanical versus hydraulic. Collapse, burst ratings and limitations of
components, if using an hydraulic hanger
DRILLING ENGINEERING
CONSIDERATIONS
Page 14 of 28
Defining accurate downhole parameters such as pressure, temperature and
drilling/completion fluid systems, to check for ratings and sealing compatibility, for
cementing packers, liner hanger packers etc
Allowing adequate time to design, specify, procure and manufacture non-standard
equipment
5.4.2
Slurry Designs
Slurry stability and retarder responses are the two most important issues. The higher
temperatures along with the higher retarder concentrations will tend to thin the slurry to
such an extent, that the slurry may become unstable. Thus any testing will need to
simulate downhole conditions.
The retarder system is critical. Important to ensure that variations in retarder
concentrations and variations in temperature will not harm the slurry’s thickening time,
compressive strength and other properties.
Compatibility with the drilling fluid systems is a key area requiring attention.
Particularly, if using synthetic oil based mud systems (SOBMs).
In addition, if the well is planned as a long-term producer, silica flour slurry designs
may also be required for the surface casing strings (due to long-term temperature
effects and breakdown on standard cement).
Some of the cementing additives that require assessment for an HPHT slurry
design are:
Fluid loss additives
Retarders
Weighting agents
Anti gas migration stabilisers
5.4.2.1
Slurry Testing
When testing slurry designs for HPHT applications, it is critical to ensure that realistic
tests are performed. For example, curing the freewater at atmospheric conditions on
the lab bench cannot represent the behaviour of the slurry at HPHT conditions. The
areas that require close attention in the laboratory are:
Temperature: Temperature data should not rely on the API schedules but take into
account downhole temperature gauge measurements, simulations of bottom hole
circulating temperature (BHCT) and actual well offset data
Pressure: The thickening time test should be performed at the actual BHP applied
by the hydrostatic mud weight and column of spacer and cement. Also to obtain an
accurate compressive strength development, the test pressure used should be
close to the actual pressure that the cement will experience at downhole conditions
DRILLING ENGINEERING
CONSIDERATIONS
Page 15 of 28
Fluid Loss: The temperature typically affects the fluid loss control of a cement
slurry. The fluid loss value will normally increase as the temperature rises, although
with some fluid loss additives it seems that the higher the temperature, the lower
the fluid loss value. There are two different test procedures for testing fluid loss
control; API FL test (maximum to 190F) or the Stirring Fluid Loss (at actual BHCT).
The stirring fluid loss test is the most realistic test for HPHT conditions
Thickening Time: This test should simulate as close as possible the job execution
offshore. This should include the time the mixwater takes to prepare, if mixed in a
pit, or other tank. A mixwater aging test should also be performed to ensure
physical properties of the slurry, as prepared to API, would not change. A safety
margin should be allocated to batch mix the slurry (if batch mixed, 60 to
120 minutes is generally acceptable). In addition, retarder sensitivity tests should
be performed to determine the effect of ‘more or less’ retarder added to the slurry
and the effect that a lower, or higher BHCT can have on the design
Sensitivity Testing: The slurry design should be tested for thickening time at
temperatures +20 and -20F on the estimated BHCT. At the higher BHCT the
thickening time should still be long enough to account for placement plus two hours
of safety. The reason for testing at 20F lower than estimated BHCT is that in some
cases there is a so called ‘S’ curve effect ie at lower temperatures the slurry
pumping time may be less than at higher temperatures. Assuming that there is no
‘S’ curve effect, if the slurry pumping time is extremely long at the lower
temperatures, it may be required to test the compressive strength at the lower
temperatures. In some cases the tests are performed at different slurry densities
(eg +/-0.25ppg). These tests determine the robustness of the slurry
Rheology: There is an optimum balance to achieve for HPHT slurries:
To remain stable under downhole temperatures and pressures
To be mixed readily by the equipment offshore and to be easily pumped
downhole
These two objectives may not be easily achievable. Testing should be done at the
mix temperature and at 190F and where in cases the BHCT is greater than 190F,
the slurry should be conditioned in the HPHT consistometer to the BHCT prior to
taking the rheology and freewater. Alternatively the HPHT rheometer should be
utilised to determine the rheology profile of the slurry at downhole conditions. The
HPHT rheometer should be used only on the final design
DRILLING ENGINEERING
CONSIDERATIONS
Page 16 of 28
Freewater: This test needs to be performed beyond APIs recommendations to
ensure that the freewater value is zero at downhole conditions. The slurry should be
conditioned in the HPHT consistometer. Once it has reached the BHCT and
conditioned for a time at BHCT/BHP, it should then be cooled to 190F, prior to
being placed in the cylinder. The cylinder is then placed into a water bath at 190F
for 120 minutes. If the well is deviated, the cylinder should be inclined at 45. At the
end of the curing period measure the freewater, and by inserting a rod into the
cylinder, determine if any settling is present. This will give an initial appreciation of
the slurry’s stability, or settling tendencies
Static Gel Strength: A test for this property (SGS) is recommended for two reasons:
To determine the transition time and confirm if the slurry is gas tight. As a guide
the transition time for a gas tight slurry should be around 30 minutes
To determine the zero gel time which would indicate the time available to
retrieve the liner running tool. For a safe operation, the zero gel time would
typically exceed 60 minutes
Pilot Tests: Prior to submitting the cementing programme, the HPHT liner slurry and
plug designs will need to be pilot tested. This can be waived only if a similar design
(additives and slurry weight) at almost identical conditions have been previously
tested. Extrapolating or interpolating from given slurry designs to meet a new set of
conditions and requirements can be inaccurate and is not advised. During the pilot
testing a full set of tests will need to be performed including sensitivity testing,
especially if the slurry design is new with no previous data
Lab tests with Rig Samples: Confirmation with rig samples is a must. Cement
samples must be tested to confirm the required level of Silica Flour prior to slurry
testing. It is important that tests are performed with a representative rig sample.
Small Silica Flour content variations can have a big effect on slurry properties.
Similarly, rig chemical samples must be used for the final testing. If more than one
lot of each retarder exists on the rig, make sure that tests are performed with each
one unless one lot number can be isolated for the job. The equality of additives
should be checked and drillwater should be tested for chloride levels
DRILLING ENGINEERING
CONSIDERATIONS
5.4.3
Page 17 of 28
Spacers
Spacer designs should ensure stability at downhole conditions, especially since the
spacer is likely to be heavily weighted with solids. The spacer volume should ensure
good separation of the cement/mud and usually higher amounts are recommended
than a standard well, especially if the weight difference between the mud and slurry is
close. It is important to identify additives that are stable at high temperatures and can
also maintain suspension of the weighting agent.
The spacer system should be tested for stability with the same emphasis as a cement
slurry. This should include compatibility tests, for both mud and cement. For example,
for an HPHT liner, it is recommended to confirm the compatibility with an actual rig mud
sample, prior to the job, as there may be differences between a lab prepared mud and
actual rig sample.
5.4.4
Simulations
Wellbore simulations should be conducted with software that takes into account the
rheology, hydraulics, pore/fracture pressures, LOT data, temperatures, casing design
and mud system. Simulations should be performed to determine optimum pumping and
displacement rates. Accurate rheology is needed not only for the cement slurry but also
for the spacer and the mud. It is recommended to use Fann 70 rheologies for the mud.
For the spacer and cement the HPHT rheometer can be used for critical slurries. In
cases where there is a long cement column, perform simulations to ensure the cement
at the top of the column will set within a reasonable time (due to the change from a
maximum BHCT, to a much lower value higher up).
Issues to consider for cementation simulation are:
Displacement rates and pressures
Losses during displacement/breakdown of fracture gradient over the narrow pore
and fracture regimes, for the HPHT transition zone
Mud properties and conditioning of the system to obtain the required PV/YP and
gels prior to and during cementing (checking for sensitivity of the mud properties on
displacement)
Hydraulics and pressure losses, including ECD effect in the annulus on identified
weak zones
Defining the optimum displacement rates for the spacer, to displace the mud from
the casing/formation in the annulus
Estimation of total job time to ensure cement does not set prior to end of job, with
an adequate safety margin (part of the sensitivity testing in the laboratory)
Impact of cementing liners in small hole sizes, to obtain a realistic concentric
cement sheath
DRILLING ENGINEERING
CONSIDERATIONS
5.4.5
Page 18 of 28
Temperature Estimation
Obtaining an accurate BHCT is critical for HPHT slurry design. API schedules for these
extreme conditions may be inaccurate, generally by overestimating temperatures. This
is better in terms of placing a safe slurry as it provides a safety factor in terms of
available pumping time. However, other properties such as compressive strength may
be affected. It is therefore recommended to run a temperature simulation programme
and/or run a (BHCT) temperature gauge. MWD temperatures will not give an accurate
estimated temperature profile for BHCT.
5.4.6
Contingency Planning
Prior to the start of the well, various cementing contingencies should be defined and
assessed and put in place ready for use as part of the well design programme. They
include the following issues for consideration:
Squeeze plugs with cementing string (low LOTs, loss zones)
Tieback strings
Plug and abandonment/suspension with cementing strings. (Design of plugs to
minimise risk of communication from HPHT zones to normally pressured zones
may require substantial cement volumes)
Balanced plugs (loss zones)
Squeeze plugs by cementing through the bit
A plug may have to be used for losses, or well control purposes. It is therefore
important that emergency cement plugs are designed that they can be pumped and
displaced through BHAs with adequate bypass. Bits should thus be run without nozzles
(if hydraulic simulations permit this), in order to allow pumping of the lost circulating
material (LCM) and cement to the zone of concern.
For small diameter holes such as 5-7/8in, the volumes of slurries for cement plugs will
be small (eg 500ft plug in open hole will be 17bbl). If conducting abandonment or
suspension operations, contamination requires consideration, (plus use of wiper darts
through the combination drillstring), to provide control over cement placement and
pressures.
Dedicated cement strings should be available for the various hole sizes (especially
small hole), together with adequate materials and up to date slurry designs to perform
emergency cement plugs at short notice.
DRILLING ENGINEERING
CONSIDERATIONS
5.5
Page 19 of 28
TEMPERATURE PROFILES
An accurate temperature profile is a must for an HPHT project. The influence and
impact on using good quality data has a significant impact on all aspects of the well.
This will include the following subjects:
Casing design
DST/completion design
Fluid programmes (drilling, DST and completions)
Cementation programmes
Capability and operating envelope for the drilling rig
Surface equipment such as DSTs
Design, operating envelope and limitations on equipment. eg Safety critical systems
such as BOPs, wellheads, packers, connections, seals, de-rating of tubulars
NACE requirements for H2S and CO2
Logging tools, MWD, logging while drilling (LWD)
5.5.1
Temperature Hazards
The influence of high temperatures and thermal effects can also amplify wellbore
hazards. Thermal modelling should typically consider the following subjects at an
early stage:
Loss of casing integrity
Loss of surface equipment seal integrity
Overpressuring of annuli
De-rating effect on equipment
Instability of fluid column
Effect on the drilling fluid
Poor cementation
DRILLING ENGINEERING
CONSIDERATIONS
5.5.2
Page 20 of 28
Temperature Sources
Temperature data should be obtained from as many sources as possible and will
generally include the following:
Maximum recorded logging temperatures
Extrapolated formation temperatures from logs
DST temperatures
Maximum recorded RFT temperatures
A profile of the undisturbed formation temperature is then constructed from all of the
data sources, as part of the HPHT datapack.
5.5.3
Modelling Temperature Profiles
It is usual practice to utilise a temperature prediction and thermal modelling programme
for HPHT wells during the planning and operational phase. There will be different
requirements depending on the assessment topic. For example, for cementation
analysis, the most important criteria is BHCT (bottom hole circulating temperature). For
casing design we need to know the temperature profile for the complete wellbore
including the BHST (bottom hole static temperature).
Temperature predictions, analysis and assessment would typically be performed for the
following subjects at the design phase:
Maximum drilling fluid temperatures
Maximum temperature of produced fluids
Circulating temperature profiles for all hole sections
Circulating temperature profiles for running/cementing casing strings
Influence of annular fluid on the maximum wellhead flowing temperatures (heat
transfer issues to outer casings) eg unweighted water packer fluid will be lower than
a weighted SOBM
Maximum/minimum casing and annulus temperatures during the life of the well. eg
hottest during long-term production and coldest during injection
Minimum temperature downstream of choke when circulating out a well influx
(required for the well control bridging document)
DRILLING ENGINEERING
CONSIDERATIONS
Page 21 of 28
All of the above cases are influenced by: The drilling circulating rates and reservoir
production flowrates, fluid types, weights, rheologies, time and limitations on the
operating envelope of the equipment. Changing one of the variables for a particular
case, will impact all subsequent assessments. This requires a detailed iterative
approach when conducting thermal modelling. Additionally, the well should be
monitored during its construction phase to check assumptions and data do not exceed
the boundary limits of the temperature model.
If the well is planned offshore, the temperature profile should also take into
consideration the water depth and temperature from the seabed to surface.
The actual temperature profile for the well from TD to surface may produce a series of
gradients, which could be above or below, the average geothermal gradient.
Information obtained from thermal modelling studies is important, as it provides a
datum for identifying suitable equipment and sealing systems, for the HPHT well.
5.6
WELLBORE EVALUATION
Wellbore evaluation includes formation evaluation, casing wear and cement integrity
monitoring. This section also includes MWD tools for surveying purposes, as many of
the electronic issues apply equally to the MWD as well as LWD equipment.
5.6.1
Formation Evaluation
Formation evaluation data can be obtained from LWD and Wireline logging, at the end
of the hole section. The LWD tools will generally be run with the MWD survey
equipment. Wireline equipment may be utilised to either verify the LWD data, or
provide the main data due to the LWD limitations.
When preparing a logging programme, attempt to reduce the complexity of wireline and
LWD equipment designs for HPHT wells.
The following issues should be considered for HPHT wells when assessing and
utilising LWD/MWD systems:
Allow adequate time to plan for HPHT equipment. Although they are becoming
more widely available, the planning and timeframe required is greater than
conventional equipment
Once the LWD objectives have been identified (including additional modular
requirements such as pressure while drilling) check that all systems are compatible.
For example, it may be necessary to utilise two systems from different vendors.
Check that the links to the mud logging systems and data files are also compatible
to allow downloading and processing direct at the rigsite eg ASCII file formats.
Minimise and avoid if possible, processing away from the rigsite
DRILLING ENGINEERING
CONSIDERATIONS
Page 22 of 28
The biggest single issue affecting the performance, operation and reliability of these
systems is the temperature of the well. Pressure does not appear to be a major
issue regarding performance. By definition, HPHT wells are hot and this has a
dramatic impact on the electrical components and the life of the battery systems.
(However, temperature degrades the seals which then collapse under high
hydrostatic pressure.)
Standard equipment is usually rated up to a maximum temperature range of 300F
(150C). HPHT equipment is generally rated up to c.350F although they have been
run at higher temperatures with success. The technology is evolving and systems
are under development to improve on the temperature limit up to 400F.
Use of heat shields are a must and the technology is evolving constantly to improve
reliability and operational performance. For example, the electronic chassis now
include new developments, such as ‘surface mount technology’ with additional heat
sinks, to disperse the heat away from critical components
As the wells are drilled deeper, the formations become increasingly harder, leading
to dramatic increases in shock and vibration. This has an impact on reliability and
so requires additional sensors to monitor downhole parameters, such as vibration,
torque and weight on bit. This also requires the systems to be optimised in
conjunction with the bit, to minimise bit whirl and vibration
Tool availability will also depend on the size required. For example, LWD systems
are available and capable of drilling HPHT wells down to 5-7/8 to 6in hole, for most
requirements (eg 4-3/4in diameter tools for Resistivity, Density, Gamma Ray and
directional MWD). Systems are constantly under development for smaller tools to
allow use in smaller hole sizes
When specifying and assessing systems for HPHT wells, spend time to consider
and discuss with the vendors issues such as, QA/QC and the resulting MTBFs
(mean time between failures) of the system sensors, including onshore and rigsite
use of calibration procedures. Keep the systems simple ie avoid complex
combinations
Operational planning requires that LWD/MWD systems are designed to allow as
much flexibility for contingency operations as possible. For example, adequate
bypass areas to allow pumping of LCM material and conducting emergency
cementing operations through the BHA and bit
To minimise risk of LWD component damage, it would be a normal practice to
perform a number of intermediate circulation’s while running in the hole. The
purpose would be to reduce the delta temperature prior to reaching bottom eg the
components do not experience extreme temperature changes. However, too many
temperature cycles can have a detrimental affect on the electrical components
Compatibility and calibration (resistivity) requirements to the mud system (eg SOBM
or WBM)
DRILLING ENGINEERING
CONSIDERATIONS
Page 23 of 28
The pressure while drilling (PWD) tool (also known as the annular pressure while
drilling tool - APWD), has replaced calculations with direct, real time downhole
measurements and in doing so has exposed the limitations of conventional surface
measurement techniques for estimating annular ECDs. These types of tools are
becoming much more widely used in HPHT applications and are essential to obtain
a much more accurate real-time assessment of downhole pressures. This assists
decision making for mud flowrates, overbalance/underbalance and verification of
LOT data, at previous casing shoes
Pulser systems are also highly susceptible to failure in an HPHT environment,
although it is possible to still have the downhole recorded data but lose real time
transmission. Developments are ongoing to increase the MTBF of components for
pulser systems
LWD/GR/Resistivity may assist the wellsite geologist in recognising the stratigraphy
associated with the high pressure transition zone
The pore pressure/fracture gradient (PPFG) tool and software model calculates
pore and fracture pressures on a foot by foot basis through mixtures of all major
lithologies (shale, sandstone, limestone, salt anhydrite) in normally compacted
sedimentary sequences. The information is obtained in real time and downhole
memory mode. The overburden pressure determination requires initial calibration to
a leak off test, which is updated using a calculated porosity, matrix density and
formation fluid density. The tool can assist in identifying changes in the pore
pressure trend, along with traditional wellsite methods (cuttings, background gas,
drilling breaks) while drilling through the high pressure transition zone
The following issues should be considered for HPHT wells when utilising wireline
logging tools:
Keep the wireline logging tool runs as simplistic as possible, even if it means
multiple runs
Detailed preparation, planning and communication with the wireline company is
critical, at an early stage
Wireline logging objectives will also require samples to be taken at specific points in
the well. This may include RFT (repeat formation tester), MDT (modular dynamic
formation tester), or CST (chronological sample tester). Obtaining and verifying
maximum static temperatures will also be required to assist with the final design of
the DST programme
If the wireline logging programme is extensive over a number of days, additional
wiper trips may be required to ensure the wellbore temperatures do not degrade the
mud system and to check that the well is not deteriorating, or masking an influx
Cable strength is downgraded due to the high temperatures, resulting in a reduced
overpull capability. This can influence the maximum weight of the tools if
considering combination runs
DRILLING ENGINEERING
CONSIDERATIONS
Page 24 of 28
Consider a fusible weak point within the cable system (activated electrically) as this
allows greater pulling strength to free the cable, eg a mechanical weak link may be
limited to 70% of the cable strength.
5.6.2
Casing/Cement Integrity Monitoring
Wireline logging programmes will not only run tools to obtain well objectives but also to
obtain and confirm the hole size, casing condition and cement integrity.
For example, use of the correct hole calipers (single, 4 or 6 arm) will have an influence
on the cement volumes pumped and the eventual top of cement (TOC). This has an
impact on the casing design and backup gradients for assessing external loads and
providing a thermal bleed-off capability for the well annuli.
Casing wear wireline tools may require benchmark calipers prior to drillout of the main
production casing, followed by casing wear assessment caliper surveys, before
testing/completing the well (MFCT/USIT). However, the attenuation may be too high to
use the USIT in high density mud, in order to provide realistic data.
Cementation integrity tools will typically include a CBL/VDL/GR/CCL. An imaging
evaluation tool such as a CET may also be used. However, in high density mud the
attenuation may be too high, to provide realistic data. For example, they will confirm
isolation of weak zones/sandstones behind the production casing. The CBL is still the
main tool to use in assessing cement integrity for high temperatures and high mud
weights.
5.7
IDENTIFICATION OF TRANSITION ZONE
Identifying the high pressure transition zone is a critical issue, for picking the
production casing (10-3/4 x 9-7/8in) shoe depth. Time spent in identifying the depth for
the production casing could save a contingency drilling liner and avoid drilling small
hole sizes. The transition zone formations may not be readily visible by conventional
logging and wellsite analysis techniques. However, in order to identify the pressure
transition zone, the methods used will depend upon the dominant overpressured
generating mechanism.
For example:
Porosity reduction by use of porosity tools, such as resistivity, sonic, neutron
porosity and density
Fluid expansion overpressure
If the above techniques are not as reliable, then it is critical to identify the formation and
stratigraphy, which is acting as the seal, to the underlying overpressure regime.
Page 25 of 28
DRILLING ENGINEERING
CONSIDERATIONS
The following two techniques have been used successfully in certain instances to
identify seismic reflectors, which are apparently associated with the pressure
transition zone:
Vertical seismic profile (VSP)
Seismic while drilling (SWD)
Use of such techniques requires extensive research and understanding of the
overpressure system for the geological regional basin under assessment.
5.8
SLIMHOLE DRILLING
The design and complexity of HPHT wells requires contingencies to be planned at an
early stage if a casing string has to be committed early. Hence, the well design is a
continuous circular approach, to identify minimum hole sizes and drift diameters. The
casing design may be planned with additional liners for the lower portion of the well.
Slimhole drilling can generally be considered to start from 6in and below.
The following example demonstrates the need to discuss casing options and issues at
the planning stage, with members of the multi-discipline team.
String
Casing Size (inches)
Hole Size (inches)
Conductor
30
36
Surface Casing
20
26
Intermediate Casing
13-3/8
17-1/2
Production Casing
10-3/4 x 9-7/8
12-1/4
Drilling/Production Liner
7
8-3/8
Drilling/Production Liner
4-1/2
5-7/8
Drilling/Production Liner
----
3-3/4
The above example illustrates the importance of placing the production string in the
right place and having additional casing strings available in the event of the following:
Hole problems such as loss/gains, or stuck pipe
Requirement to sidetrack the well due to hole problems
Well control incident
Poor LOT at the intermediate casing, requiring commitment of production casing
early within the high pressure transition zone
Poor LOT at production casing, requiring commitment of a drilling liner
DRILLING ENGINEERING
CONSIDERATIONS
Page 26 of 28
All of the above issues and sizes need to be assessed, modelled and reviewed in
terms of:
Hydraulics/high ECDs
Limitations of drilling equipment, such as the drillpipe strength
Ability to perform fishing operations
Specialised float equipment to allow drillout with PDC bits
Obtaining a satisfactory cement sheath for the hole size/pipe combination
Availability and supply of equipment such as bits, turbines, mud motors, survey
tools, LWD/logging tools. (LWD/MWD equipment would probably not be available
for 3-3/4in hole)
Sensitivity of small kick tolerances and the ability of the rig to identify the influx (in
particular, on a semi-submersible)
Ability to achieve the DST/completion objectives (eg possible need to test in
open hole)
The example illustrated is only one example. There are many casing permutations and
hole sizes that could be considered to achieve slightly larger hole sizes. However, the
issues requiring assessment are the same.
5.9
WELL MANAGEMENT
This section is focused toward HPHT developments and highlights areas relating to the
management of the reservoir.
A significant number of issues can be eliminated at the planning stage, by spending
time and resources to design the completion for a ‘zero workover’ strategy. Although
this is a planned objective, HPHT wells may require intervention to address:
Equipment failure, eg sub-surface safety valves
Sand/scale problems
Reservoir management
Sand production may lead to tunnel perforation failure, which cannot be handled by
production measures such as reducing the drawdown. This may then require a suitable
rig to access the well.
Production decline due to depositional problems (scale and/or salt deposit,
permeability reduction, perforation plugging) may be treatable by pumping fluid down
the tubing and/or through a wireline unit, coiled tubing or snubbing unit.
DRILLING ENGINEERING
CONSIDERATIONS
Page 27 of 28
The reservoirs are characterised by high salinity formation brines. As a result, scaling
problems may be more severe than standard reservoirs and so requires a strategy for
dealing with the problems. Scale inhibitors should therefore be modelled and tested to
check for thermal instability and brine incompatibility.
Reservoir management in terms of pressure decline has an impact on the Net Asset
Value (NAV) of the project. The development drilling schedule may require all wells to
be drilled prior to producing the reservoir, because of the risk of drilling into a depleted
reservoir with an overpressured seal above. This can lead to extreme cases of losses
coupled with well control problems.
5.10
EMERGING TECHNOLOGY
Many of the issues that originally affected HPHT developments have been resolved eg
capability of wellheads, xmas trees, downhole safety valves and packers. However, the
biggest challenge that needs to be improved upon is the ability of equipment to cope
with deeper, hotter, higher pressure wells. This has an impact on well designs, as it
may mean drilling smaller hole sizes, with the use of the contingency strings to achieve
the well depth.
In particular, LWD/MWD systems need to be developed further, to provide smaller
tools and electronics that can withstand the higher temperatures and pressures.
Elastomer technology will need to ensure longer life and reliability, to cope with higher
temperatures for the new tools under development.
Examples of emerging technology for HPHT wells are summarised below.
5.10.1
Expandable Solid Tubular Technology
This system uses pressure and an internal mandrel, to expand the casing diameter and
so allow full bore access for drilling out. The potential benefit of the technology could
allow casing shoes to be extended after the original casing has been installed. For
example if a loss/weak zone is encountered, or a critical LOT is lower than the
minimum required (intermediate casing) to drill through the transition zone. The system
could be utilised on a production casing or liner and thus save a casing string and hole
size. If the system were to be utilised, contingency planning would be required, to
install a modified float shoe in advance, as part of the well design.
DRILLING ENGINEERING
CONSIDERATIONS
5.10.2
Page 28 of 28
Mud Pulse Telemetry
An HPHT packer can be set using a pulse based communication technique, similar to
that used in MWD and well testing applications, which actuates and manipulates
downhole completion tools equipped with onboard electronics. Downhole tools
programmed at the surface to recognise one of a series of discrete commands from a
portable terminal unit, are actuated using a computerised supervisory control and data
acquisition (SCADA) system to control pressure wave pulse frequency. The tools are
equipped with a downhole power source, a smart (programmable) board and an
actuating device. This promotes more efficient operations and removes a potential
wireline run for installing a plug to set and test the packer.
5.10.3
Coil Tubing Perforating
Perforating systems are now using coil tubing as the means of pacing the guns at the
reservoir. A development of this technology for correlating the guns on depth with the
GR and casing collars is by a wireless system, ie the coil tubing does not require an
electric line to be run through the reel as part of the perforating system. This is
beneficial from a safety and cost perspective, as it removes a cable inside the coil for
closing the BOP system.
SECTION 6
Drilling and Production Operations
Ref: HPHT 06
SPECIAL WELLS MANUAL, VOLUME I:
HIGH PRESSURE, HIGH TEMPERATURE
Issue: Feb 2000
MANAGEMENT AND CONTROL
Page 1 of 26
TABLE OF CONTENTS
6.
MANAGEMENT AND CONTROL .......................................................................... 3
6.1
DRILLING RIG SPECIFICATIONS AND CONTRACTUAL
CONSIDERATIONS ......................................................................................... 3
6.1.1
Pre-hire Acceptance Inspection.................................................................. 3
6.1.2
Pre-hire Environmental Inspection.............................................................. 4
6.1.3
Rigsite Personnel ....................................................................................... 5
6.1.4
Operational History..................................................................................... 5
6.1.5
Maintenance ............................................................................................... 6
6.1.6
Office Based Personnel .............................................................................. 6
6.1.7
Variable Deck Load Capacity...................................................................... 6
6.1.7.1
Prior to Running 13-3/8in Casing ............................................................... 7
6.1.7.2
Prior to Running 10-3/4 x 9-7/8in Casing.................................................... 7
6.1.7.3
During Transit ............................................................................................ 7
6.1.8
Dynamic Response and Station Keeping.................................................... 8
6.1.9
Bulk Storage Facilities .............................................................................. 10
6.1.10
Subsea Package Handling System........................................................... 10
6.1.11
Marine Riser System ................................................................................ 10
6.1.12
Well Control Equipment............................................................................ 11
6.1.13
Drilling Fluid Circulation System ............................................................... 12
6.1.14
Mud Cleaning and Solids Control Equipment............................................ 13
6.1.15
Cementing System ................................................................................... 13
6.1.16
Well Test Facilities ................................................................................... 14
6.1.17
Drainage System ...................................................................................... 15
6.1.18
Sewage System........................................................................................ 15
6.1.19
Gas Detection System.............................................................................. 15
6.1.20
Third Party Equipment .............................................................................. 16
6.1.21
Derrick/Hoisting Equipment ...................................................................... 16
MANAGEMENT AND CONTROL
Page 2 of 26
6.2
RESPONSIBILITIES OF RIGSITE PERSONNEL .......................................... 16
6.3
MEETINGS..................................................................................................... 17
6.3.1
Pre-spud Meetings ................................................................................... 17
6.3.2
Mid-well Meeting....................................................................................... 18
6.3.3
Daily Meetings .......................................................................................... 18
6.3.4
Pre-tour Meetings ..................................................................................... 18
6.3.5
Prior to Non-standard Operations ............................................................. 19
6.4
TRAINING ...................................................................................................... 19
6.4.1
Well Control Drills..................................................................................... 19
6.4.2
HPHT Well Control ................................................................................... 20
6.5
HYDROGEN SULPHIDE................................................................................ 21
6.6
BLOWOUT CONTINGENCY PLAN ............................................................... 22
6.7
RELIEF WELL PLAN ..................................................................................... 22
6.8
RISK ANALYSIS............................................................................................ 23
6.8.1
Hazard Assessments................................................................................ 23
6.8.2
Suspension of Operations ........................................................................ 25
MANAGEMENT AND CONTROL
6.
Page 3 of 26
MANAGEMENT AND CONTROL
This section includes issues to consider for the management and control of: high
pressure, high temperature (HPHT) drilling rigs, personnel responsibilities, training, well
control, H2S, blowout contingency planning and risk quantification. Most of the subjects
listed here require good audit, hazard identification and training systems, not only to
remove risk during the well design but also to be able to control the hazards, if they
occur.
6.1
DRILLING RIG SPECIFICATIONS AND CONTRACTUAL
CONSIDERATIONS
The drilling of HPHT wells requires a drilling unit that is not only capable from a
technical perspective but also has a strong track record of drilling these types of wells.
For example, having available in house technical backup for subjects such as riser
analysis, engineering equipment limitations and well control training. This requires the
operator to allow sufficient time to work with the drilling contractor and main service
companies, at an early stage of the project.
The timing and commencement of an HPHT project will be driven by the availability of a
suitable drilling unit, especially if drilling offshore. Resources spent at this phase of the
project in identifying a suitable rig can save considerable expense in hidden costs at a
later date, such as rig upgrades and operating efficiency. For example, conceptual
planning will have to be carried out in house by the operator, plus additional third party
studies, to identify if a jack-up or semi-submersible is required and suitable for the
location site.
The following subjects summarised below assume an offshore semi-submersible rig
has been identified as the preferred choice.
6.1.1
Pre-hire Acceptance Inspection
Most rig tender documents are now based on a standard IADC (International
Association of Drilling Contractors) template and modified to suit additional
requirements. It is recommended this approach is adopted for specifying the
requirements for an HPHT bid invitation and technical assessment.
Prior to a formal contract award, the operator and an independent surveyor should
perform a pre-hire inspection of the rig. The inspection should include an examination
of equipment condition and standards of maintenance, in accordance with API
Standards, IP 17, NACE, local legislation relating to health and safety, and the
equipment manufacturer’s original specifications and recommendations. The inspection
should typically include the following subjects:
Internal examination of safety critical equipment, eg blowout preventer (BOP)
system, drilling chokes and marine equipment
Examination of maintenance records and calibration tests, performed on critical well
control components and load carrying equipment
MANAGEMENT AND CONTROL
Page 4 of 26
Oil sampling from equipment for analysis
Function testing, load testing, pressure testing and insulation resistance checks on
equipment where considered necessary
Note: A good inspection assessment criteria is the ability of the rig to satisfy the
minimum requirements of the IP 17 document.
Rig acceptance should be conditional upon a satisfactory inspection report of the rig.
The drilling contractor should carry out for example, any maintenance work or repairs
deemed necessary by the inspection team for the project, prior to contract
commencement.
It is wise to establish outstanding issues between the drilling contractor and regulatory
authorities on safety incidents or safety record, which may impact the rig contract, or
start date of the project.
If rig modifications are required to satisfy the required standards of documents such as
IP 17, they should be assessed and discussed with the drilling contractor, to determine
payment responsibilities and the potential impact on the timing of the project
(eg shipyard booking schedules).
6.1.2
Pre-hire Environmental Inspection
Prior to a formal contract award, the operator and an independent survey team should
perform a pre-hire environmental inspection of the rig. The inspection should include
examination of procedures, equipment condition and standard of maintenance in
accordance with the manufacturer’s original specifications and recommendations. The
audit should pay particular attention to personnel awareness of procedures and the
measures in place to reduce the risk of an environmental incident.
An environmental inspection would typically include the following subjects and should
be performed at the same time as the pre-hire inspection:
Capability of the Shipboard Oil Pollution Emergency Plan
Rig drainage systems
Oil spill clean up equipment
Fuel bunkering equipment and procedures
Note: It is important to understand that the degree of environmental compliance
required for the rig, will vary based on local rules and legislation.
Establish if there are issues outstanding between the drilling contractor and regulatory
authorities on environmental compliance, which may impact the rig contract or start
date of the project.
MANAGEMENT AND CONTROL
6.1.3
Page 5 of 26
Rigsite Personnel
The safe and efficient success of all projects is down to the quality and experience of
the personnel. It is important to ensure the key personnel for the rig have adequate
knowledge and experience of HPHT wells. The operator should obtain from the drilling
contractor the resumes of personnel during the planning and operational phases of the
project. It is important to assess the overall stability of the rig crew and onshore support
team. Examples of key personnel are:
Rig Manager
Engineering support (onshore technical support in the planning phases with the
operator)
Rig Superintendents
Toolpushers
Drillers
Assistant Drillers
Derrickmen
Master/Barge Engineers
Subsea Engineers
Emphasis should be placed on the training and work history related to experience of
HPHT operations.
6.1.4
Operational History
The operational history of the rig should be assessed to determine the types of HPHT
wells and areas in which the wells were drilled.
For example, is the rig currently working on an HPHT well, or has it been some time
since an HPHT well was drilled? This has an impact on drilling contractor efficiency for
an HPHT project.
Is the rig a new drilling unit, with no work history to date? A situation such as this
should be avoided for an HPHT project. However, if rig availability is very limited, what
options exist for a drilling campaign to include basic low risk wells, prior to a
critical well?
The above issues may even result in the project being delayed or deferred, until a
suitable unit with a previous work history is available.
MANAGEMENT AND CONTROL
6.1.5
Page 6 of 26
Maintenance
The operator should include as part of the pre-hire surveys, clear evidence of
maintenance systems in place. This should include records of all maintenance
performed on the rig, with a clear focus on critical equipment, such as BOP systems,
pressure integrity of pipework and links to the rig survey programme, by the rig class
certification authority.
6.1.6
Office Based Personnel
The operator should obtain a current organisation structure from the drilling contractor,
for both onshore and offshore management structures. In particular, how onshore
technical backup supports the offshore operation for subjects such as:
Engineering problems
Equipment assessment
Ensuring systems are up to date and complied with, by internal audit
6.1.7
Variable Deck Load Capacity
This is a critical subject as it can have an influence on the ability to drill and test the
well to a specific depth. It can also have an impact on operational logistic costs, due to
weather constraints, well location and space/capacity on the rig.
The operator should obtain engineering dimensional drawings of the complete rig deck
area. This should show the typical positions of equipment packages, tubulars, and third
party equipment and well test surface packages for drilling, testing and completion
operations.
The ideal situation is high variable deck load (VDL)/space that is more than the
minimum requirements. This will depend on the age and generation of rig. For
example, new design heavy duty HPHT rigs are now fifth generation units which have a
high specification. However, there are a number of older drilling units which are more
than capable of drilling HPHT wells, provided the operator has a clear understanding of
the well design and issues, to address with contractors at an early planning stage.
The drilling contractor should provide VDL calculations to confirm the rig can operate
with the maximum anticipated VDL requirements. Examples include:
MANAGEMENT AND CONTROL
6.1.7.1
Page 7 of 26
Prior to Running 13-3/8in Casing
All standard deck loads due to anchoring, bulks, permanent rig equipment, standard
third party equipment should consider issues such as:
Maximum length and weight of the intermediate 13-3/8in casing including the
casing contingency
How much 5in, 6-5/8in drillpipe and BHA can be racked back in the derrick
All of the barytes and cement silos full
The maximum surface mud volume and mud weight
The maximum volume of base oil in storage assuming an SOBM or OBM system
6.1.7.2
Prior to Running 10-3/4 x 9-7/8in Casing
All standard deck loads due to anchoring, bulks, permanent rig equipment, standard
third party equipment should consider issues such as:
Maximum length and weight of the production 10-3/4 x 9-7/8in casing including the
contingency
How much 5in, 6-5/8in drillpipe and BHA can be racked back in the derrick
All of the barytes and cement silos full
The maximum surface mud volume and mud weight
The maximum volume of base oil in storage assuming an SOBM or OBM system
6.1.7.3
During Transit
Provide confirmation that with the maximum VDLs indicated, it is possible to
accommodate the maximum well mud weight in the pits, with the rig at survival draft.
The operator should obtain confirmation that the rig meets certified stability
requirements for the various VDL combinations.
The operator should also obtain the maximum mud weights that the rig can transfer
and hold in terms of load strength/sq. foot for the pits and pontoons if stored away from
the mud pits.
MANAGEMENT AND CONTROL
6.1.8
Page 8 of 26
Dynamic Response and Station Keeping
Dynamic response and station keeping capability should also be confirmed for the well
location, based on the time of year and water depth. Issues requiring consideration are:
Confirmation of the details and capability of the rig position/riser angle monitoring
system, using transponder beacons on the BOP/lower marine riser package
(LMRP)
Procedures for rapid disconnect of riser and emergency move off location in any
direction
Details of the rig motion characteristics including graphs of the following:
Heave to wave height ratio versus wave period
Pitch to wave height ratio versus wave period
Roll to wave height ratio versus wave period
The drilling contractor should provide the following matrix, with the operating limits for
the rig.
Note: This is important, as it has a direct influence on the rig riser analysis and
capability of the wellhead connector/conductor design.
MANAGEMENT AND CONTROL
Page 9 of 26
OPERATING LIMITS
ACTIVITY
Crane Operations
Vessel loading/
offloading.
Deck equipment
handling.
Heavy lifts.
Equipment
Handling
Through moonpool.
Deploy subsea
equipment.
Recover subsea
equipment.
Drilling
Drilling Ahead.
Tripping.
Circulating at shoe.
Well Testing
Run tubing.
Wireline ops.
Coil tubing ops.
Marine Riser
Disconnect/
reconnect criteria.
SIGNIFICANT
WAVE HEIGHT
(FT)
WIND
SPEED
(FT/S)
SIGNIFICANT
HEAVE (FT)
PITCH
ROLL
(DEGREES) (DEGREES)
MANAGEMENT AND CONTROL
Page 10 of 26
The drilling contractor should provide details and history of waiting on weather (WOW)
time for wells drilled in similar areas and operations in progress, at the time of
suspending operations.
Details of mooring equipment failures should be included with recommended tensions
and a basic API riser analysis for the area proposed.
Note: This should link if required, to the IP Guidelines for ‘Routine’ and ‘Non-Routine’
Subsea Operations from Floating Vessels for a riser analysis.
6.1.9
Bulk Storage Facilities
The rig bulk storage facilities should be assessed and confirmed for the well design
together with the maximum volumes that may be required for drilling and testing the
well. This should include assessments of the following:
Barytes
Base oil
Cement
Fuel oil
Brine
Marine loading points for all of the above should be available on both the port and
starboard sides of the rig.
6.1.10
Subsea Package Handling System
The drilling contractor should provide confirmation on the ability to perform a pressure
test of the complete BOP system, to full working pressure on a test stump, while
performing routine rig floor activities.
Ability to handle, move and provide sufficient deck area for subsea xmas trees and drill
stem testing (DST) equipment.
6.1.11
Marine Riser System
The drilling contractor should provide confirmation that the marine riser system
includes a riser booster line hooked into a centrifugal pump from the mud system, for
circulating at higher rate up the marine riser to clear cuttings. This is of particular
importance when drilling 16/17-1/2in hole.
Additionally, confirmation from the riser analysis that the complete system is capable of
working at various operating conditions with maximum mud weights and pressures at
the wellhead/BOP (high mud weights and pressures mean more rigid and hence stiffer
systems).
MANAGEMENT AND CONTROL
6.1.12
Page 11 of 26
Well Control Equipment
Well control equipment and requirements will depend on the well control policies of the
operator and should also refer to the IP 17 document. Such issues have been
discussed in earlier sections of this manual and the reader should refer to these.
However, additional issues to consider may include:
Size and operating envelope of wellhead connector. (Important as this is related to
the riser analysis and the limitations of the gasket types for temperature, peak and
continuous performance)
Facility for fitting ‘bullseye’ inclination measuring devices on the BOP and/or
the LMRP
Availability of a tool for drifting the BOP stack and LMRP to full bore
Details of ram configuration if using 6-5/8in drillpipe
Capability of the pipe rams for hanging off the complete drillstring weight with the
blind/shear rams, shearing pipe above the hung off tool joint
Optimising the BOP ram configuration for drilling and testing requirements, with the
correct variable bore rams
In addition to satisfying the requirements of IP 17, the contractor should provide
confirmation of certification, by providing up to date copies of certificates for all safety
critical BOP components. Examples include but are not limited to:
Flexible hoses on choke and kill lines, detailing continuous and short temperature
and pressure ratings. Also age of the hoses and replacement criteria policy
BOP ram face seals detailing continuous and short term temperature and pressure
ratings
Elastomer seals within the well control system detailing continuous and short-term
temperature and pressure ratings
Well control equipment conformity for sour service under NACE
Details of any exposure of well control equipment to H2S over a timeframe,
including exposure time, pressures and temperatures experienced and H2S
concentration
A dimensional engineering drawing and schematic drawing showing the complete
surface well control circulating and venting system
Records of all well control incidents over a timeframe, including maximum
pressures, temperatures, well complications, equipment failures and servicing after
the well control incident
Details of downtime on the BOP system over a timeframe
MANAGEMENT AND CONTROL
Page 12 of 26
Details of maintenance programme including wall thickness checking, internal
examination and seal replacement of the well control system
Details on the use and wear of the rams and annulars, to determine the available
life for stripping operations
Details of the calibration programme performed on all pressure gauges operating
within the well control system
An engineering dimensional and schematic drawing of the LMRP and BOP stack
showing the positions of all main components with dimensions between the rams
and other relevant space out dimensions
6.1.13
Drilling Fluid Circulation System
The operator should discuss the requirements of the fluids circulation system with the
drilling contractor for the well design, maximum weights and fluid types to be used.
Examples include but are not limited to:
The total available surface mud volume
The total capacity of the slug pits with a defined minimum volume that can be
pumped (eg 50bbl)
Capability to take mud pumps suction directly from any pit
A minimum of two mixing lines, to allow independent simultaneous operations, eg
mixing reserve pit pre-mix, while transferring, or mixing into the active system
Equipment for the high rate addition of barytes to the mud system, for fast weight
up operations
Return flowline, flow metering device with output to the drillers console
Minimum of two pit level sensors on all active pits. A combination of both
mechanical and acoustic sensors is recommended. (Sensors should be positioned
to allow for rig movement)
Mechanical and electronic trip tank level sensor, with output visible from the driller’s
console
Three mud pumps with the ability to circulate with a total horsepower output
equivalent to 1,000gpm at 5,000psi
In addition to the above items, the drilling contractor should provide details of the
following:
An up to date schematic drawing, detailing the rig low and high pressure
circulating systems
MANAGEMENT AND CONTROL
Page 13 of 26
Specifications of all standard pump liners available, including size, pressure rating,
volume output and pressure relief valve settings
Pressure ratings of the mud pump well control/kill system, ie mud pumps, standpipe
manifold and top drive system
6.1.14
Mud Cleaning and Solids Control Equipment
The operator should discuss the requirements of the fluids circulation system with the
drilling contractor for the well design, maximum weights and fluid types to be used.
Examples include but are not limited to:
Rig floor drainage system to collect all drilling fluid from the drill floor, with a facility
to return to the mud system
All liquids from the rig drainage system to go to the oil water separator, to ensure
minimal dumping of oily liquids
Totally enclosed/sealed mud bucket with line to the trip tank
Suitable ventilation from the shaker room to allow use of SOBM
Minimum of 4 shale shakers suitable for cuttings volume generation with an SOBM
Centrifuge package for control of mud weight and drilled solids. This package
should consist of a minimum of two centrifuges, which can be run either in parallel
for solids dump, or in series for barytes recovery
In addition to the above items, the drilling contractor should provide details of the
following:
Details of any cuttings wash/treatment equipment installed on the rig
An engineering dimensional drawing showing the proposed location of the cuttings
wash/treatment system
6.1.15
Cementing System
In addition to the issues raised in IP 17, the operator should obtain confirmation of
the following:
Maximum delivery rate of the bulk system to the cement unit
The ability to accommodate a full 100bbl batch tank (assuming a slurry density of
18ppg), including location, hook up and communication links to the main cement
unit and rig floor
MANAGEMENT AND CONTROL
6.1.16
Page 14 of 26
Well Test Facilities
The operator should obtain confirmation of the capability to perform a wide range of
DST/completion activities and should link to at least one, or more, well test service
vendors. Many of the issues to consider should be addressed by the use of IP 17.
However, items that should be assessed in conjunction with IP 17 include but are not
limited to:
A 15,000psi rated standpipe to the test flowline, used for connecting coflexip
flowline hose from the flowhead. (A second standpipe for the kill line coflexip would
be advantageous but not mandatory)
A 15,000psi rated production test line, which runs from the drill floor to the
nominated test area
Permanent pipework, which connects the test area to the burner, booms, including
date of installation, material specification, ID, OD, certification, maintenance
records and end connections
A method of relieving pressure from the hydrocarbon vessel relief valves. This is
normally in the form of a relief line header block. The relief lines shall be a minimum
nominated ID and rated to an agreed pressure with the operator. The relief lines
should include details of installation date, material specification, certification, and
maintenance records and end connections
A plan view of the test area on the rig showing hazardous areas during the test.
A surface equipment layout of a previous HPHT test should be included as a
reference guide
Details of the burner boom rig up, including:
King post certification
Length of booms
Drawing outlining boom type
Details of the following utilities, which are required for testing equipment:
Rig air
Diesel fuel
Potable water
Electricity for data systems
Sufficient firewater for deluge during flaring
Steam supply (if available)
Lighting to illuminate the test area
Temporary communication facilities in a well test lab cabin
MANAGEMENT AND CONTROL
6.1.17
Page 15 of 26
Drainage System
The drilling contractor should confirm the facilities and systems for:
The facilities in designated ‘open deck drainage areas’ or ‘clean areas’ which
normally discharge directly overboard, that can re-direct all deck liquid flow into the
‘contaminated area’ or ‘closed drainage system’ for treatment in an oily water
separator if required
Oil water separator facilities for treating the bilge and machinery space drainage
system, each with a capacity of treating a defined volume per hour. The facilities
shall include waste oil holding tanks, prior to transportation ashore for suitable
disposal and/or recycling of the separated oil. The facilities shall also include an on
line oil content metering system, capable of monitoring that the oil content is less
than a defined value (eg 15ppm). This should automatically close the overboard
discharge line for the treated water and re-route the oily waters back to the oily
water collection tank
Procedures and sampling/testing regime to ensure that the on line oil content
metering system does not exceed an oil content level of more than a defined value
(eg 15ppm)
6.1.18
Sewage System
The drilling contractor should confirm the facilities for:
Treatment of raw sewage and domestic water, prior to disposal with the digested
effluent being cleaned and disinfected by chlorination, before being discharged to
the sea. The discharge point shall be located below water level, while the rig is at
normal drilling draft
The effluent from the sewage system shall produce effluent that is free of
suspended solids, with chlorine content to a certain level of so many mg/litre and a
defined faecal level per ml
Drilling contractor should provide procedures and a sampling/testing regime, to
ensure that the effluent from the sewage system is free from suspended solids
6.1.19
Gas Detection System
The drilling contractor should confirm the following:
Details and location of gas detectors, including drawings of locations and layouts
Details of the maintenance and calibration performed on the gas detection system
MANAGEMENT AND CONTROL
6.1.20
Page 16 of 26
Third Party Equipment
The drilling contractor should provide details for the following:
Engineering dimensional drawings showing the typical locations of the standard
third party equipment packages, ie mud logging unit, wireline unit and tool cabin,
MWD/LWD containers and H2S cascade system containers
Details of any third party equipment currently installed on the rig
6.1.21
Derrick/Hoisting Equipment
The drilling contractor should provide details for the following:
The minimum derrick load handling capacity
Note: This should be checked against the maximum anticipated weight of the casing
strings.
The top drive system, including service history and details of failures and downtime
Details of the casing string maximum loads run by the rig
Details of the pipe handling system and the ability to rack back an estimated length
of 6-5/8in drillpipe (this will have to be estimated, as part of the initial proposed
BHA/hydraulics planning)
6.2
RESPONSIBILITIES OF RIGSITE PERSONNEL
The responsibilities of the rigsite personnel should be addressed as part of the well
control bridging document; in order to define lines of communication and actions
required, for a well control emergency situation.
The exact details of the roles and responsibilities will depend upon the well control
document used as the primary system (operator, or drilling contractor). Once this has
been agreed, specific roles can be expanded within the document. Additionally, IP 17
(Section 3.4) provides a good guide for the duties of individual personnel, for a typical
well control situation.
The chain of command and reporting relationships should be prepared as flowcharts
for onshore and offshore.
Other issues to consider for the HPHT well control bridging document include, but are
not limited to:
The operator should have two drilling supervisors at all times for 24 hour coverage
The drilling fluids company should provide two Mud Engineers to give 24 hour
coverage of the well
MANAGEMENT AND CONTROL
Page 17 of 26
The operator should provide a Geologist on the rig to supervise the mud logging
contractor and to provide the operator Drilling Supervisor/drilling contractor
adequate data, on the formations and pore/fracture pressure regimes
Assuming the rig is an offshore unit and depending upon the local legislation, the
drilling contractor OIM (Offshore Installation Manager) will be the person in charge
of the installation at all times
Section 3 of IP 17 provides a guide on ‘Responsibilities and Administration’ and
discusses issues such as, communications, operator supervision, level of supervision,
duties of individual personnel and recommended crew for emergency well control
situation.
6.3
MEETINGS
The success of an HPHT project depends upon all team members attending and
contributing to regular meetings, to ensure well objectives and safety of the well are
maintained at all times. This should include onshore and offshore personnel during the
planning and operational phases of the project and include the operator, drilling
contractor and all service companies.
The following safety meetings should be held and recorded, at various phases of the
project.
6.3.1
Pre-spud Meetings
These should be held onshore at the operator’s office and include all relevant
personnel associated with the HPHT project: drilling contractor, service company
managerial and supervisory staff prior to the spudding the well. The purpose of the
meeting should be to explain and communicate the well design and programme,
including hazards and areas of concern. A separate more detailed onshore meeting
should also be held for well testing operations.
A similar pre-spud meeting should be held offshore to communicate the well
programme to the supervisory and service company personnel on the rig. Issues
requiring action should be allocated to specific personnel and recorded in the minutes
of the meeting.
Subjects to present should typically include:
Background information
Well objectives
Geology
Safety policies
Well design
Drilling programme
MANAGEMENT AND CONTROL
Risk assessment
Logistics and materials
Safety
6.3.2
Page 18 of 26
Mid-well Meeting
Due to the long duration of HPHT wells, a second programme should be held onshore
and at the rigsite. This should be conducted prior to drilling out the intermediate casing
string or prior to entering the high pressure transition zone. The main purpose of the
meeting should be to re-emphasise the special procedures that are required, when
drilling into HPHT formations.
6.3.3
Daily Meetings
A safety meeting should be held and minuted at the start of each day, to discuss the
current and planned operations. The meeting should be attended by:
The OIM, Toolpushers, operator Drilling Supervisors, Driller, Geologist, MWD/LWD
Engineers, Barge Engineer, Mud Engineers and Mud Loggers. The meeting minutes
and actions arising should be sent to the operator Drilling Superintendent and drilling
contractor Rig Manager.
6.3.4
Pre-tour Meetings
Meetings should be held prior to the start of each tour, to co-ordinate the handover
between the drilling crews. The meeting should be run by the OIM, or Toolpusher and
include the following personnel:
OIM
Toolpushers
Driller
Assistant Driller
Derrickman
Floormen
Mud Engineer
Mud Logger
MANAGEMENT AND CONTROL
6.3.5
Page 19 of 26
Prior to Non-standard Operations
Safety meetings should be held for special operations and prior to testing the well. The
meetings should be designed to explain operations that are non standard, or
unfamiliar. All personnel associated with the operation should be present and made
fully aware of the procedures to be adopted and possible hazards that might occur
during the operation. These type of meetings should be held offshore and would be
separate and additional to any hazops performed previously.
6.4
TRAINING
Training forms a critical part of an HPHT project, therefore adequate time and
resources should be allocated to ensure all of the rig crews are trained in the correct
drilling practices, well control, H2S and emergency procedures to be adopted for
the well.
Drills should be used on a regular basis to ensure the drill crews are fully familiar with
the procedures and techniques, that may be required when drilling a HPHT well. The
toolpusher should ensure that the drills are performed regularly and in accordance with
the written procedures.
6.4.1
Well Control Drills
For specific details on drills, please refer to the Repsol Well Control Manual. These
would include the following standard drills:
D1 Kick While Tripping
Kick While Drilling (including hanging off the drillstring)
Diverter Drill
Accumulator Drill
Well Kill Drill
In addition to the standard drills, special well control techniques which may be
employed on HPHT wells should also be carried out.
These include:
Stripping Drill (Annular and Ram)
Bullheading
Emergency Disconnect Procedure (semi-submersible). Prior to spudding, or when
the rig is disconnected from the wellhead, a drill should be performed to simulate an
emergency winch off from the location
MANAGEMENT AND CONTROL
6.4.2
Page 20 of 26
HPHT Well Control
Adequate time and resources should be allocated to ensure all personnel, both
onshore and offshore involved in decision making and/or supervisory capacity, attend a
specific HPHT well control course. The following personnel should typically attend
these types of courses:
OIM
Toolpushers
Operator Drilling Superintendent
Operator Drilling Supervisors
Operator Geologists
Operator Drilling Engineers
Rig Manager
Drillers
Assistant Drillers
Derrickmen
Mud Engineers
Mud Loggers
MWD/LWD Engineers
Cementing Engineers
The course should be prepared jointly by the operator and drilling contractor and
should cover the following topics:
Overview of the well
Standard well control sections
Detection of the transition zone, mud weights and properties, swab/surge pressures
How to utilise the well objectives to minimise the use of the contingency liner
Contingency planning
The course should discuss HPHT issues based on the following subjects:
Past experiences and practices
Gas behaviour and implications
Review of rig equipment
MANAGEMENT AND CONTROL
Well specific decision trees
Surface gas handling equipment capacities and limitations
Hydrates formation and corrective actions
Effects of pressure and temperature on mud properties
Well scenario
Practical drills applying procedures and practices
Human factors and well control mistakes
6.5
HYDROGEN SULPHIDE
Page 21 of 26
There are many aspects of an HPHT well to consider in terms of the wellbore fluids.
One of the critical issues is the potential hazard arising from H2S. Therefore, unless it
can be conclusively proven that H2S will not be present, all high pressure surface
equipment that could potentially be exposed to well fluids should be designed and
specified as sour service. The same criteria should be applied to the casing, DST and
completion designs and all well programmes.
Well test programmes should be defined to ensure safety from the effects of H2S. As it
is colourless, highly toxic, flammable and heavier than air, the precautions that apply to
any operation where it may appear as a component of the gas must be taken into
account, as testing brings the wellbore fluids onto the installation.
Areas where the atmosphere can contain toxic H2S fumes in concentrations that could
endanger personnel shall be hazardous area classified. This should include planning,
monitoring systems, personnel protective equipment and systems, training and drills.
If the rig is not installed with a complete H2S system, a third party service specialising
in this type of equipment should provide a full H2S cascade detection system, breathing
apparatus and training, prior to drilling into any formations of known, or expected H2S
presence.
Performing operations such as coring recovery at surface, DST sampling, blowing
down DST surface equipment pressures, breaking chicksans and/or lubricators, shall
be performed according to special safety precautions and procedures.
MANAGEMENT AND CONTROL
6.6
Page 22 of 26
BLOWOUT CONTINGENCY PLAN
A blowout study and contingency plan should be prepared for the HPHT well as part of
the well design and also the well control bridging document. The blowout study should
link to Appendix 2 of IP 17 ‘Worst Case Scenario for the Drilling of High
Pressure Wells’.
By performing this type of study, it allows the maximum temperature of the wellhead
system to be calculated and confirm if the minimum period of one hour for rig
evacuation is adequate, in terms of equipment and elastomer ratings. It also allows the
thermal load to be determined and utilised, as part of the casing design for the
thermal loads.
The blowout contingency plan may be a generic document that is already in place and
modified for HPHT purposes. It would involve the drilling contractor and some of the
main service companies, such as cementing, fluids and directional/surveying. Issues
requiring consideration may include the following:
Emergency organisation and location of key personnel
Well control procedures (agreed and finalised with drilling contractor at an early
stage of the project)
Specialised well control equipment and services based on a call-out contract
Assessment of hazardous fluids, such as H2S and CO2
Logistics and ability to supply critical equipment and bulk products at short notice
(materials and transport)
Relief well planning for an independent well kill, if the well is unable to be killed and
capped
6.7
RELIEF WELL PLAN
The relief well plan should consider the following issues:
Relief well target selection
Surface location selection (if offshore, potential availability of a suitable semisubmersible or jack-up. If on land, access and size of existing pad for additional rig)
Relief well trajectory design, directional and surveying. This demands an accurate
survey programme for the original well design, in order to have a high confidence
level of intersecting the original well ie survey error radius of uncertainty
Casing shoe selection and design
Kill fluid design (well will be deviated and probably longer in terms of
measured depth)
Dynamic kill modelling (use of a specific well control modelling programme)
MANAGEMENT AND CONTROL
Page 23 of 26
Kill equipment specification and availability
Kill operations including a proposed programme
Gas dispersion modelling of the existing well under blowout conditions and impact
on drilling rig and surrounding area
Subsea plume modelling (if drilling from a floating vessel and blowout is at the
wellhead/BOP)
The dynamic kill model should assess an underground as well as a surface blowout.
Reservoir data is critical to the generation of the relief well plan, so that the blowout
model is as accurate as possible. As the drilling programme progresses, the data
obtained should be reviewed and compared to the data used in the relief well plan. If
substantial differences exist, the relief well plan should be modified as required, in
order to ensure it remains valid.
6.8
RISK ANALYSIS
The whole process of HPHT well planning and programmes should be based on
identifying the hazards and the risk reduction measures, for all stages of the project.
It is becoming routine to conduct well operations on this basis by using these types of
techniques and requires the involvement of a wide range of personnel, at each
respective stage of the assessment.
6.8.1
Hazard Assessments
Well designs such as HPHT will require the use of HAZOP/HAZAN techniques as part
of the well planning and design process, due to the close design margins and the
consequences of failure. To assist the members of the team, HAZOP comes first by
identifying the hazards from the design and means Hazard and Operability study. It is
qualitative and is performed by a team from a cross-section of various disciplines, not
just drilling personnel. The hazards are identified and the team then decide how to
address them. The HAZAN process then follows, by analysing the hazards, it is
quantitative and may include techniques such as risk assessment, or quantified risk
assessment (QRA) (ie what is the likelihood that an incident, or failure will occur and
the consequence should it occur).
The hazard assessments should break the project down into modular packages,
eg subjects such as well design, drilling operations, well control, rig moves (if offshore),
DST/completion operations, well suspension/abandonment operations. The various
subjects may link to specific studies and outputs, which have been generated by
different members of the project team.
Page 24 of 26
MANAGEMENT AND CONTROL
A table is generally produced, based on the following format or similar, with some
examples on how it could be used:
OPERATION
ITEM
Drilling
Operations
A
Well Control
Procedures
B
INHERENT
HAZARD
POTENTIAL
CONSEQUENCES
RISK REDUCTION
MEASURES
Pressure
overload of
casing
Burst or collapse of
casing
Casing strings are
designed to withstand
expected shut-in surface
pressures for burst and
collapse. Production
casing designed to
withstand expected
shut-in maximum
surface pressures
Loss of
primary well
control
Potential influx of
hydrocarbons into
wellbore, possibly
resulting in blowout
Primary control
maintained using a fluid
of sufficient density to
overcome predicted
formation pressures with
an overbalance by:
Ensuring rheology
properties of the fluid
are such that the density
can be increased as
necessary by adding
material.
Ensuring sufficient
volume of fluid is
available at surface,
including a specified
volume and weight of
‘kill fluid’.
Maintaining sufficient
stocks of:
Barytes (weighting
material).
Cement.
Lost circulation
materials.
Mud chemicals.
MANAGEMENT AND CONTROL
6.8.2
Page 25 of 26
Suspension of Operations
It is normal practice for HPHT well programmes to include, as part of the contingency
policies and plans, requirements for the suspension of operations.
This is defined within IP 17 Section 6.1.1 (d) as:
‘The criteria for the suspension of operations, or abandonment of the well, or of that
section of the hole giving rise to continuing problems, where the safety margin of
operations in progress is deteriorating, should be stated.’
Drilling operations should be suspended as soon as safely practical if any of the
following situations occur (which are not listed in terms of priority). The situation will be
investigated and remedied, or deemed no longer hazardous, prior to any drilling
operations recommencing.
Note: All of these issues should have been discussed as part of the hazard
assessment process.
Well conditions, or well integrity dependent equipment, are subjected to conditions
outside its operating envelope. Examples are: pressure, temperature, H2S and CO2,
excessive casing wear or dynamic losses exceeding a predetermined value)
Vital safety equipment, including its backup becoming inoperable (pressure/
temperature/H2S/hydrocarbon monitoring equipment, life saving appliances, kill
weight and mixing equipment if no kill mud in reserve, cement unit not operational,
mud logging gas detection system not operational)
Stock levels of barytes, whole mud, mud chemicals, cement, cement chemicals,
base oil and hydrate suppressant volumes fall below their identified minimum stock
levels
Weather conditions deteriorate outside the operating envelope of the drilling rig
(eg semi-submersible riser analysis, bending moment limits of the wellhead
connector/BOP)
Well directional survey plan approaches upon the ‘minimum distance of separation’
for existing wells if drilling from a platform, subsea cluster or land drilling well slot
pad
In addition, drilling ahead should be temporarily stopped, if any of the following
examples occur:
Temperature of drilling fluid returns exceeds a pre-determined maximum
The difference between the LOT and maximum mud weight in use falls below a
pre-determined value (eg 0.5ppg)
Background gas rises to an unacceptable level
MANAGEMENT AND CONTROL
Page 26 of 26
Any kick indication, drilling break, increased returns, flowrate, pit gain, hole not
taking correct volume during trip, change in properties of returned mud, increase in
hookload, pump pressure decrease/pump stroke increase
All of the above subjects should be addressed as part of the well control bridging
document, during the planning phase.
SECTION 7
Drilling and Production Operations
Ref: HPHT 07
SPECIAL WELLS MANUAL, VOLUME I:
HIGH PRESSURE, HIGH TEMPERATURE
Issue: Feb 2000
REFERENCES AND FURTHER READING
Page 1 of 7
TABLE OF CONTENTS
7.
REFERENCES AND FURTHER READING ........................................................... 2
REFERENCES AND FURTHER READING
7.
Page 2 of 7
REFERENCES AND FURTHER READING
(1)
Institute of Petroleum: Model Code of Safe Practice Part 17 ‘Well Control during
the Drilling and Testing of High Pressure Offshore Wells’, May 1992.
(2)
Institute of Petroleum: Guidelines for ‘Routine’ and ‘Non-routine’ Subsea
Operations from Floating Vessels, August 1995.
(3)
NACE Standard MR0175-99.
(4)
API:
Specification 6A, Wellhead and Xmas Tree Equipment.
(5)
API:
Specification 6FA, Fire Test for Valves.
(6)
API:
Specification 6FB, Fire Test for End Connections.
(7)
API:
Specification 6FC, Fire Test for Valve with Automatic Backseats.
(8)
API:
Specification 16A, Drill Through Equipment.
(9)
API:
Specification 16C, Choke and Kill Systems.
(10)
API:
Specification 16D, Control Systems for Drilling Well Control Equipment.
(11)
API:
RP 16E, Design of Control Systems for Drilling Well Control Equipment.
(12)
API:
RP 16Q, Design, Selection, Operation and Maintenance of Marine
Drilling Riser Systems.
(13)
API:
Specification 17D, Subsea Wellhead and Xmas Tree Equipment.
(14)
API:
RP 53, Blowout Prevention Equipment Systems for Drilling Operations.
(15)
ISO:
13628-4, Petroleum and Natural Gas Industries Drilling and Production
Equipment Design and Operations of Subsea Production Systems Part 4 Subsea Wellhead and Tree Equipment (Based on API
Specification 17D).
(16)
ISO:
10423, Petroleum and Natural Gas Industries Drilling and Production
Equipment Specification for Valves, Wellhead and Xmas Tree
Equipment.
Note: Check that the API documents and other standards/codes are the most up to
date edition, prior to use.
The web address for the most up to date listing of all API documents is:
http://www.api.org/cat/pubcat.cgi
The various codes and API standards can be obtained from:
TSSL (Technical Standards Services Limited), Hitchin, England
Tel +44 1462 453211
Fax +44 1462 457714
Web http://www.techstandards.co.uk
Email sales@techstandards.co.uk
REFERENCES AND FURTHER READING
Page 3 of 7
(17)
Economides MJ, Watters LT, Dunn NS Petroleum Well Construction,
Wiley 1998.
(18)
Articles
Reference
Author
Article
Journal
Euroil, October 1997
Under Pressure: HPHT could be the
place to be
Journal
Hart’s Petroleum
Engineer International.
Jeanne P Perdue,
Technology Editor
Predicting and Preventing Casing
Wear While Drilling
JPT
JPT June 98. Thomson
K, Adamek FC
High Pressure, High Temperature
Platform Wellheads and Xmas
Trees
OTC Paper 8742
JPT
Hilts RL, Kilgore MD,
Turner WH (JPT
June 97)
Development of a High Pressure,
High Temperature Retrievable
Production Packer
(SPE Paper 36128)
Journal
Hart’s Petroleum
Engineer International
August 96
Pulse Wave Actuates Downhole
Tools
JPT
JPT June 97.
Samuelson ML,
Constein VG
Effects of High Temperature on
Polymer Degradation and Cleanup
(SPE Paper 36495)
JPT
Ray TW (JPT June 98)
High Pressure, High Temperature
(HPHT) Seals for Oil and Gas
Production (SPE Paper 39573)
Journal
von Flatern R (Offshore
Engineer June 99)
Pressure to Complete
Journal
Holbrook P
(SPEDC March 97)
Discussion of A New Simple
Method to Estimate Fracture
Pressure Gradients
JPT
Element DJ, van der
Vossen, Diamond S,
Hamilton TAP
(JPT June 98)
Consequences of Formation
Breakdown During Well Control:
A Study of Underground Crossflow
While Drilling an HPHT Well
(SPE Paper 38478)
REFERENCES AND FURTHER READING
Page 4 of 7
JPT
Sundermann R, Bungert D
Potassium-Formate Based Fluid
Solves High-Temperature Drill-in
Problem
JPT
Van Oort E, Bland RG,
Howard SK, Wiersma RJ,
Roberson L
Improving High Pressure, HighTemperature Stability of Water
Based Drilling Fluids
JPT
Harrison JR, Stansbury M,
Patel J, Todd Cross A,
Kilburn M
Novel Lime-Free Drilling Fluid
System Applied Successfully in
Gulf of Thailand
Halliburton Aberdeen
Engineering
HPHT Cementing Guidelines
JPT
Patel AD, Wilson JM,
Loughbridge BW
Impact of Synthetic Based Drilling
Fluids on Oilwell Cementing
Operations
Journal
Hunt E, Pursell D (World
Oil September 96)
Fundamentals of Log Analysis
JPT
Gardner D, Fallet T,
Nyhavn F (JPT March 97)
Production Logging Tool
Developments for Horizontal
Wells and Hostile Environments
(SPE Paper 36564)
Journal
Tollefsen E, Everett M
(World Oil December 96)
Logging while fishing technique
results in substantial savings
JPT
Technology Digest
Addressable Release Tool for
Electric-Line Use
Journal
von Flatern R (Offshore
Engineer August 98)
A better feel for formations
Journal
Hart’s Petroleum Engineer
International May 98
MWD/LWD Comparison Tables
Journal
Jackson M, Einchomb C
(World Oil March 97)
Seismic While Drilling:
Operational experiences in
Vietnam
Journal
Kamata M, Underhill W,
Meehan R, Nutt L (Harts
Petroleum Engineer
International October 97)
Real-Time Seismic-While Drilling
Offers Savings, Improves Safety
Journal
Holm, G (Oil and Gas
Journal January 98)
How abnormal pressures affect
hydrocarbon exploration,
exploitation
REFERENCES AND FURTHER READING
(19)
Page 5 of 7
JPT
Graham GM, Jordan MM,
Graham GC, Sablerolle
W, Sorbie KS, Hill P,
Bunney J (JPT June 97)
Implication of High-Pressure/
High-Temperature Reservoir
Conditions on Selection and
Application of Conventional Scale
Inhibitors: Thermal Stability
Studies (SPE Paper 37274)
Journal
Harts Petroleum Engineer
International August 96
Mud Pulse Telemetry: Pulse
Wave Actuates Downhole Tools
Journal
Grow, JJ (World Oil
April 99)
Expandable Casing Update
Ward, Dr CD (Sperry-Sun
Drilling Services)
A new approach to Pore and
Fracture Pressure evaluation
Journal
Goins Jr, WC (World Oil
October 96)
Learning from well control
mistakes can help prevent future
blowouts
Journal
Eby, DF (Offshore
January 97)
Precautions in planning HPHT
well control
SPE Papers. The web address for the Society of Petroleum Engineers is:
http://www.spe.org
Paper
Number
Author(s)
Title
35076
Smith JR, Cade RS,
Gatte RD
Integrating Engineering and Operations
for Successful HPHT Exploratory Drilling,
SPEDC Dec 1997
55052
Jellison MJ, Eckroth
JJ, Fulton J, Ogren
LA, Moore PW,
Barber V, Vesely D
Teamwork Results in World Record
Length Casing Run
20900
Krus H, Prieur JM
High Pressure Well Design
52884
Miska SZ,
Samuel GR,
Azar JJ
Modelling of Pressure Buildup on a
Kicking Well and its Practical Application
56853
Watson, RJ
Discussion of Modelling of Pressure
Buildup on a Kicking Well and its
Practical Application
24603
Cassidy S
Solutions to Problems Drilling a High
Temperature, High Pressure Well
REFERENCES AND FURTHER READING
Page 6 of 7
26874
Seymour K,
MacAndrew R
Design, Drilling and Testing of a
Deviated HTHP Exploration Well in the
North Sea
26738
Oudeman P,
Bacarreza LJ
Field Trial results of Annular Pressure
Behaviour in a High pressure, high
temperature Well
36583
Stewart RB, Gill DS,
Lohbeck WCM,
Baajens MN
An Expandable Slotted-Tubing, Fiber
Cement Wellbore Lining System
56921
Hinton, A
An Analysis of OSD’s Well Incident
Database; Results can Improve Well
Design and Target Well Control Training
23120
Davidson A R, Prise
G, French C
Successful High Temperature/High
Pressure Well Testing from a
Semisubmersible Drilling Rig
26874
Seymour K,
MacAndrew R
Design, Drilling and Testing of a
Deviated HTHP Exploration Well in the
North Sea
28297
Ward CD, Coghill K,
Broussard, MD
The Application of Petrophysical Data to
Improve Pore and Fracture Pressure
Determination in North Sea Central
Graben HPHT Wells
27488
Bowers GL
Pore Pressure Estimation from Velocity
Data: Accounting for Overpressure
Mechanisms Besides Undercompaction
22557
Morita N, Fuh GH,
Boyd PA
Safety of Casing Shoe Test and Casing
Shoe Integrity After Testing
24603
Cassidy S
Solutions to Problems Drilling a High
Temperature, High Pressure Well
28710
Rocha LA,
Bourgoyne AT
A Simple Method to Estimate Fracture
Pressure Gradient
18036
Peters EJ,
Chenevert ME,
Zhang C
A Model for Predicting the Density of OilBased Muds at High Pressures and
Temperatures
24589
Edward-Berry J,
Darby JB
Rheologically Stable, Nontoxic, High
Temperature, Water-Based Drilling Fluid
REFERENCES AND FURTHER READING
Page 7 of 7
29071
Growcock FB,
Frederick TP
Operational Limits of Synthetic
Drilling Fluids
28305
Miano F, Carminati
S, Lockhart TP,
Burrafato G
Zirconium Additives for High
Temperature Rheology Control of
Dispersed Muds
39282
Rommetveit R,
Bjorkevell KS
Temperature and Pressure Effects
on Drilling Rheology and ECD in
Very Deep Wells
38480
Swanson BW,
Elliott GS, Meier JL,
Easton MDJ
Measurement of Hydrostatic and
Hydraulic Pressure Changes During
HPHT Drilling on Erskine Field
19939
Tilghman SE,
Benge OG, George
CR
Temperature Data for Optimising
Cementing Operations
24581
Kabir CS, Hasan
AR, Kouba GE,
Ameen MM
Determining Circulating Fluid
Temperature in Drilling, Workover and
Well Control Operations