OTC 17055 rigs, simultaneously.

OTC 17055
Drilling and Completion – How to accomplish CAPEX and schedule managing up to six
rigs, simultaneously.
P.S. Rovina and G.R. Borin, Petrobras
Copyright 2005, Offshore Technology Conference
This paper was prepared for presentation at the 2005 Offshore Technology Conference held in
Houston, TX, U.S.A., 2–5 May 2005.
This paper was selected for presentation by an OTC Program Committee following review of
information contained in a proposal submitted by the author(s). Contents of the paper, as
presented, have not been reviewed by the Offshore Technology Conference and are subject to
correction by the author(s). The material, as presented, does not necessarily reflect any
position of the Offshore Technology Conference, its officers, or members. Papers presented at
OTC are subject to publication review by Sponsor Society Committees of the Offshore
Technology Conference. Electronic reproduction, distribution, or storage of any part of this
paper for commercial purposes without the written consent of the Offshore Technology
Conference is prohibited. Permission to reproduce in print is restricted to a proposal of not
more than 300 words; illustrations may not be copied. The proposal must contain conspicuous
acknowledgment of where and by whom the paper was presented. Write Librarian, OTC, P.O.
Box 833836, Richardson, TX 75083-3836, U.S.A., fax 01-972-952-9435.
The success of an offshore oil field development strongly
depends upon the well drilling success. Historically, the
development of wells is the part of the project scope that
presents the highest deviations in cost and schedule, due to the
associated geological risks and the complexity involved in
each operation. To fulfill the sanctioned CAPEX, the
Barracuda and Caratinga well team has used the best
management techniques and state-of-art drilling and
completion technologies, allowing the completion of the well
campaign on schedule and in the budget.
This project has 54 wells, being 32 for oil production and
22 for water injection, in water depths between 709 and 1119
m. The whole scope took 44 months, using, in average, four
rigs to perform drilling and completion, with a peak of six rigs
during ten months. Those rigs have drilled 143 km of
borehole; 30 km in pay zones, most of them in a horizontal
The main drives on the operational side were: safety as a
priority, a well design kept as simple as possible, and a
detailed program containing contingencies and risk analysis
for critical operations and real time drilling monitoring to
expedite corrections in the well path when facing unexpected
results in the pay zone.
On the management side, the critical analysis meetings
covered the client requirements (productivity indexes
established by the reservoir group) and guaranteed the
performance of service companies and suppliers based on
clear targets agreed at the beginning of the development.
The paper focuses on the key success factors, such as:
perfect integration between operator and service companies,
use of new technologies with the support of specialists, and
good project planning and control, structured according to the
PMBOK - Project Management Body of Knowledge.
The Barracuda and Caratinga fields are located in the Campos
Basin, 160 km east of Macae, offshore Rio de Janeiro State, in
Brazil (Fig. 1). The Barracuda field was discovered in April
1989; the reservoir contains 25o API crude and covers an area
of approximately 233 km2, in water depths between 600 and
1100 m. The Caratinga field was discovered in February 1994;
the reservoir covers an area of 260 km2, in water depths
between 850 and 1350 m, and contains 23o API oil. The
pressure and temperature are normal so the rigs hired for the
project had 10 kpsi BOP and the maximum depth measured in
a well was bellow 5000 meters.
Aiming at reservoir uncertainty reduction, a production
anticipation project – named Pilot System – was implemented.
Three exploratory wells from Caratinga and eight from
Barracuda were connected to P-34
FPSO (Floating,
Production, Storage and Offloading ) and were in production
between September 1997 and October 2002. The information
and data acquired during that phase were valuable to optimize
the location of the wells during the development phase.
The Project was developed through a major turnkey EPC
(Engineering, Procurement and Construction) Contract of over
US$ 2.6 billion – including wells; subsea flowlines, umbilicals
and pipeline; and two FPSO’s, P-43 and P-48 (Fig. 2). The
well scope of work - drilling and completion – alone
represented US$ 1.0 billion. The contract was signed in July
2000, making Barracuda and Caratinga one of the largest
offshore development projects in the upstream segment.
Despite being an EPC Contract, PETROBRAS remained
responsible for the drilling and completion of the wells and a
subcontract was celebrated between KBR (the EPC
Contractor) and PETROBRAS (the Well Contractor) to
accommodate the responsibilities.
In this scenario, no delays could be accepted in the
sanctioned well schedule and a dedicated team was built in
July 2000. The drilling of first development well started in
September and the formal asset structure was implemented in
January 2001.
Until May 2004, when the last well was completed, 5314
rig days were employed along these 44 months. If only one rig
had been assigned to the project, 14.5 years would have been
necessary to complete the scope. In fact, an average of four
rigs were used, scaling up to a peak of six rigs during ten
OTC 17055
The scope
The Project has a total of 54 wells (table 1) but only 44 were
drilled in this scope: ten wells from the Pilot System were
transferred to the permanent production system.
Among these ten wells, three were converted to water
injection wells and one was recompleted in another zone. The
other six were directly transferred to P-43 (five) and P-48
(one), involving only the subsea scope, i.e. relaying of
flowlines and hook up to production units.
Producers injectors
Table 1 – Wells scope of work
The majority of the wells – twenty-nine – should be
horizontals, according to the project basis, all of them
requiring sand control. Nine multilaterals should be drilled and
ten completed – one had already been drilled when the
contract was signed.
The Challenges
The well project bases clearly pointed out the main issues the
team should face during the development phase. Among them,
the most important are:
The well design: although the reservoir has good
petrophysical properties, its small thickness required strict
path control through the drilling of the horizontal sections.
Most of the wells had a +/-3 meter tolerance gap for
navigation through the pay zone, reaching an extreme of 1,5
meters in one well due to water contact proximity.
The multilaterals: in order to maximize the reservoir
recovery, bilateral wells have risen as a solution for both oil
producers and water injections at irregular parts of the
reservoir (Fig. 3). Multilateral completion associated with
sand control in a subsea well dramatically increase the risk of
failure. Level 5 -junction construction – the best in class at the
time – generates debris that fall on a plug set for one leg
isolation. To remove these debris and to fish the isolation plug,
a careful coiled tubing operation is required and the risk of
having the CT assembly stuck is quite high. At the beginning
of the development of the wells, a bilateral one was lost due to
a stuck coiled tubing and, later, screen failure.
The hydrates: since the production units were not
available during the well completion, the tree block should
have a proper fluid resident, keeping the oil and gas from the
production tubing away from the water left in the flowlines.
The project control: the deviations in cost and schedule
for subsea developments are frequently due to the well scope
which presents the higher risks: the most relevant are the
geological, the technological and the rig performance. One
project with this magnitude has too many interfaces and,
consequently, a high risk of over schedule or overbudget. The
project manager had to control a group of actions, such as: the
status of material procurement; legal and customs issues;
subsea interfaces and interference of units – rigs, lay support
vessel, diving support vessel, stimulation boat, supplies.
Rig interference: during the period of higher activity, four
dynamic positioned rigs, two anchored rigs and two DP lay
vessels worked together in the site. The uncertainties in the
dates of unit movements required a day-by-day critical
schedule analysi.
Christmas trees: for this project, some improvements were
applied in the subsea trees. Only GLL (guidelineless) trees
were used and the most important changes implemented were
the unique VCM – Vertical Connection Module – and piggy
back concept. The standardization was maintained,
representing a flexibility for the schedule. Any tree could be
installed onto different production bases, even if furnished by
different manufacturers. Some delays were experimented
during the qualification of tree components and during the
fabrication of the trees. Nineteen wells had to be temporarily
abandoned just after drilling and gravel packing due to the
lack of tree bases.
Meet the productivity and injectivity indexes. The
economic feasibility of deepwater development projects is
very much dependent on the high productivity of the wells.
The drives were: maximize the productivity and injectivity and
minimize the damage of the wells (skin factor). Strict control
of fluid cleanness and maximization of well extension
exposing clean sandstone became an obsession for the
The Structure
The team in the asset
Well Interventions Manager. In charge of cost control,
legal aspects, interfaces management, coordination of critical
analysis and meetings within the asset, with the Well
Services Operator Unit and service companies.
Project coordinator. Responsible for controlling the
schedule, managing the contract and technical interfaces. The
selection process inside the company considered: strong
experience in offshore well operations, solid background in
project management and ability in negotiations.
Drilling programmer. In charge of drilling planning,
control and procedures update. Having only one specialist
controlling the drilling program presents various advantages,
among them the uniformity in procedures, technical memory
and fast reaction to surpass unexpected difficulties.
Completion programmer. With a strong experience in
subsea completions, this engineer has controlled since the sand
control operations until the Christmas tree installations. The
same advantages listed for the drilling specialist are valid for
the completion advisor, in addition to the control of a larger
number of procedures to be applied in a very complex subsea
Rig Coordinator. In charge of the everyday rig well
supervision, this engineer had to guarantee the execution of
the operations according to the reservoir requirements. Any
change in the program or provision of additional resources had
to be managed by him. His profile is: an experienced company
man, assigned temporarily at the office to coordinate the rig
OTC 17055
operations. Most of the times, these engineers coordinate two
rigs simultaneously.
Fluid coordinators. Two dedicated mud engineers were
assigned to the asset during the whole well development
phase: one for drilling fluids and other for completions, gravel
packing and stimulations. They were responsible for both the
program and the execution supervision, as well as the
improvements in execution procedures.
Company man. The “eyes” of the operator aboard the rigs,
the company man has taken care of the supervision of well
execution, including HSE and technical management as well
as rig and well services control.
Planning engineer. An essential support for the project
coordinator, controlling the day-by-day performance
indicators, such as: actual cost, daily progress and earned
value, HSE indexes and the key performance indicators
negotiated with suppliers and clients.
During this development phase, the most important
interface in the asset is the reservoir team, as well as the flow
assurance and subsea team. The price of any new information
required, any change proposed for scope resulted in an
immediate economic analysis to evaluate its feasibility. This
routine has reduced the change orders to a low and acceptable
The supporting structure
E&P Service Unit. This department has played an
important role for the success in the Barracuda and Caratinga
well development. Key people were assigned to support the
asset in control planning, supply, logistics and technical
solutions in the following areas: rig contract management,
directional drilling, casing and cement, subsea equipment,
completion equipment, slickline, wireline and coiled tubing
operations, well testing and coring/fishing operations.
Desk engineers. The service company has assigned
dedicated desk engineers for sand control, well design and
directional drilling.
Asset support. HSE and legal advisors, quality assurance
and project management consulting were also important
support for the project manager.
The Solutions
Management. To face the sort of challenges pointed out
above, the team has quickly established urgent actions and
inserted them in an integrated action plan. The critical analysis
meeting was the mechanism selected to control those actions.
Initially the frequency was on a weekly basis and after one
year, one meeting per fortnight was enough, given the level of
commitment spread in the whole team.
The methodology proposed in PMBOK Guide (Project
Management Book of Knowledge) was intensively used for
this project planning and control. The planning started three
years before the EPC contract signature and has been revised
by specialists to guarantee the best time and cost estimation,
based on actual data already performed in a similar scenario.
To select the KPI (key performance indicators), two drives
were considered: minimum number, to reduce the time spent
by the engineers for this matter, and focus on core subjects and
operations. The main indicators were:
Corporate and shareholders interest (negotiated with the
asset manager) – cost, schedule and HSE KPI (lost time
incidents and non-lost time incidents);
• Client (negotiated with the reservoir manager) – an
evaluation form was created, containing the main quality
items prioritized by the client for the completed well:
execution as per approved by the well design and damage
ratio under two.
• Drilling subcontractor – the asset has controlled the main
service company through the MTBF (mean time between
failures) for motors, LWD (logging while drilling) and
MWD (measuring while drilling) equipment.
• Sand control subcontractor – the targets were: 100%
gravel placement and excellence in tool performance.
• Rig subcontractor – a service protocol was signed with the
PETROBRAS E&P Service Unit, which contros the rig
contractors. The main KPI was the rig availability. The
average performance at the end of project was above 93%
of rig efficiency.
Any failure in a given process led to a cause analysis and,
depending on the results, one of the three following mitigation
actions were taken:
• Inadequate procedure – the division in charge of given
procedure had to revise it and submit it to the asset
advisor approval.
• Human failure – immediate training was provided.
• Equipment failure – improvements were immediately
provided in the part that had bad performance.
A risk management process was also implemented. The
critical issues were revised weekly, evaluating the probability
of occurrence, the severity and the ongoing actions for
prevention or mitigation. For example, when a particular tree
supplier was in trouble to deliver the equipment and the
critical path would be affected – delay in project schedule –
two other suppliers were called to manufacture two trees each
one, in emergency (one year to deliver) to avoid any delay.
Both suppliers accomplished the targets and no delay was
experimented due to this risk.
Drilling. The advances in the horizontal well technology,
supported by the high quality of seismic data in the positioning
and geosteering of the wells, improved the productivity
indexes and enhanced the sweep efficiency of the oil, allowing
the development of these fields and meeting the economic
The main drives were:
• Safety, as a priority;
• Credibility in the well operations program, i.e. no
mistakes or omissions were allowed;
• Well project kept as simple as possible;
• Rig daily meetings to refine the operations risk analysis
and the contingencies when something fails;
• Wells drilled with real time logging and monitoring in the
office to expedite decisions.
The integrated action between the Well Intervention and
the Reservoir Teams has assured rapid and transparent
information flow, speed-up and optimized decision making.
Well planning has considered the completion needs, e.g.:
low doglegs and minimum sinuous in horizontal section to
OTC 17055
minimize problems when running in the sand control
Slender wells. The first wells drilled had the
“conservative” casing arrangement (Fig. 4), as following:
Bit diameter (pol)
Casing (pol)
13 3/8
12 ¼
9 5/8
8 ½*
5 ½** or 7***
Horizontal open hole
Screens basepipe
Directional cased wells
As soon as it was confirmed that no shallow sands
occurred in the Caratinga field, the slender concept was
adopted, i.e. the 30” casing was set and the 16”phase was
drilled without BOP. The 13 3/8” casing was set and anchored
at high pressure housing. The time spent to drill the slender
wells was about four days less than the conventional wells,
reducing rig cost plus unnecessary casing and cement.
An intensive use of technology allowed the short operator
staff to control the project properly, focusing on decision
making and spending no time to acquire or prepare data.
Among the most valuable tools used, we highlight:
• Bit inclination sensor – allowing fast track correction
when the BHA (bottom hole assembly) began to deviate
from planned target;
• PWD (pressure while drilling sensor) – monitoring the
mud ECD (equivalent circulating density), the driller had
strict control of cuttings in suspension, optimizing the
drilling rate with much less risk of the drill string getting
• Well trajectory planner;
• Conventional downhole motors plus rotary steerable
• Real time monitoring – acquisition and interpretation of
profile, reservoir characteristics and pressure data;
• Databases for seismic and geological interpretation.
The bit inclination sensor, the rotary steerable and the real
time monitoring have allowed a fast horizontal section drilling
with lower sinuous and no rugosity. The PDC bit had an
important role in complying with the tight schedule; in most of
the wells one bit alone was able to drill the entire horizontal
section of up to almost 1000 meters.
Directional pilot wells were drilled for all the horizontal
wells, providing important information on the reservoir for the
best positioning of the horizontal section, for example: top and
base of pay zone, lithology and pressure data. The real-time
acquisition enabled quick and reliable decision-making for
optimizing well path trajectories. The horizontal trajectory was
always designed to maximize the use of existing pilot well.
Sand Control. Thirty horizontal wells were completed
with open hole gravel packing (OHGP). Horizontal extensions
varied from 238 to 991 meters, with the average being 640 m,
and an accumulated length of 19200 m. Vertical and
directional wells were completed with frac-packs.
The record for a subsea well was the four-zone selective
frac-pack completion for tight spacing between zones1,
performed in a vertical well in the Caratinga field.
Thus, two paradigms were broken for open hole horizontal
gravel packing:
Water packing pumping at low flow rate. Best practices
recommend pumping the gravel using high rates to guarantee
the correct placement throughout the whole horizontal section.
In one particular well, the expected fracture gradient was too
low and, in order to prevent the risk of rat hole fracture, some
simulations were carried out, and it was decided to reduce the
rate in 40 %. The gravel was pumped at flow rates as low as
5,5 bbl/min and the 8 ½”open hole was 100% packed.
Water packing in an injection well performed with no
return. The gravel assembly was run into a horizontal section
and the packer set. During the cycling of the one trip gravel
packing tool, the open hole was swabbed and part of the mud
cake was removed, causing severe formation losses. Various
calcite peels were spotted but the losses remained. The gravel
placement was carried out, pumped at 11 bbl/min with no
return and the packing has reached 95%. After an acid job, the
injection test showed no skin in this well. All the other wells
were 100% packed.
Completion string. The production string was 13 Cr, 5 ½”
premium thread, except in four wells with higher flow rate
where a 6 5/8” tubing was ran. All the wells were equipped
with PDG (permanent downhole gauges) - quartz pressure and
temperature sensor – and TPT – Tree pressure and temperature
transducer – except the multilaterals. The production casing
was 9 5/8” so the clamp for electric cable was designed to
minimize the risk of incidents: perfect adjustment onto
couplings, round shape to easily pass through BOP and
wellhead and no bolts or nuts exposed to hit during the hole
The water injection wells were equipped with BRV (back
pressure and retainer valve) to avoid back flow just after any
stop in the pumping during the operation phase.
Typical production string composition and casing
arrangement are shown for vertical well (Fig. 4) and
horizontal well (Fig. 5).
Stimulation. All the water injectors had to be acidized to
remove the mud cake. In addition, some oil producers had
presented a damage ratio above the limit after the gravel pack
and had to be acidized. The corrosion inhibitors worked well
during the acid treatment. However, the necessary back flow
after treatment in oil producers kept the pH very low for a long
period, raising the risk of corrosion in 13 Cr screens. One
organic formulation – acetic mud acid – has mitigated this
Piggy back trees. (Fig. 6). To minimize the length of
flowlines and control umbilicals, and to save connections onto
FPSO, this concept was applied for water injection wells. The
master base has two independent chokes so the flow rate in
master well and in the slave well can be controlled separately
anytime during the well life. There are pressure & temperature
sensors and flowmeter available. The multiplex control pod
OTC 17055
and both choke modules can be removed independently using
a Lay Support Vessel, reducing workover costs.
The Christmas tree and other accessories follow the GLL
standardization. The slave well tree and adapter base are
exactly the same used in other wells.
Hydrates prevention. This issue was addressed by spotting
diesel and alcohol inside the tree block. Ethanol was used in
production trees and diesel in injection trees. This simple
procedure avoids contact of gas and remained water near the
tree wing valve during well kick-off. The previous experience
shows that, even using foam pigs as spacers when displacing
water by diesel in flowlines, the seawater is not completed
removed. The ethanol inside the tree block doesn’t allow
hydrate formation.
Rig assignment and management
Rig assignment.
The rig cost represents approximately 70% of the overall
well costs. PETROBRAS works in the Campos Basin with a
pool of floating rigs – 25 in average during the Barracuda and
Caratinga development – and this assorted fleet allows the
company to optimize the rig assignment. The rig selection for
this project considered:
DP (Dynamic Positioning) drillships for drilling. They
have good performance for drilling because the higher heave,
row and pitch (compared to semi submersible rigs) don’t
imply in downtime increase. The lower cost – again
comparing to semis – has contributed to control the CAPEX.
They were also used in completions except during winter time
when the weather conditions become rough and the efficiency
decreases. Three different drillships (Pelikan class) have
worked for the project, with a maximum of two units at the
same time.
Anchored semi-submersible for multilaterals and
completions. Bilateral wells require a very stable rig with
lower cost, due to the risks during the sand control operations
and the junction completion. Anchored semis match these
criteria, especially after the advances in pre-lay anchoring. The
total DMM (Demobilization, Movement and Mobilization)
took two or three days. This additional time for rig moving
had no impact in schedule and helped to control the CAPEX.
Two anchored semis have worked in the Barracuda and
Caratinga development, one belonging to PETROBRAS fleet
and the other one contracted.
DP semi submersible. They are suitable for subsea wells
completions and very flexible for well abandonment in case of
interference, stable enough for delicate operations such as
running of sand control assembly, tubing hanger, production
base and Christmas tree installation. Four DP semis were used
in the Barracuda & Caratinga development but only one has
worked throughout the project – the Ocean Alliance.
Rig performance. Each dynamic positioned unit has a
safety exclusion area where no other unit is admitted. This
Restriction Diagrams, also known as “killer bubble”, considers
an eventual drive off and the time to restart the unit control,
under historical current and weather conditions. These
restriction diagrams are in the 3rd generation and the software
is an important input since the preliminary project – to
optimize the well wellhead location – and during the
construction phase for rig schedule control. .
The high rig efficiency in this project is due to two
programs ongoing in the Rig Service Unit:
• DPPS (Safety Program for Dynamic Positioning Rigs).
This program establishes some procedures, regular tests
and inspections to guarantee excellent performance of the
whole DP (Dynamic Positioning) system. Since its
implementation, in 1996, the number of incidents has
been reduced in 50%. The main routines are:
• The annual inspection which is the most important one as
this procedure created an excellent practice allowing the
rig crew to solve small problems right away. The main
items inspected are: DP control, power generation, power
management system and thrusters. The crew training
status is also evaluated.
• One important routine onboard is the register of any DP
degraded status. The EDS (emergency disconnection
sequence) criteria vary according to the water depth. The
procedures establish different EDS sequences depending
on how critical the ongoing operation is. These
procedures anticipate the well abandonment in safe
conditions and the cost and the safety impacts of an
eventual disconnection.
• Another regular test is the blackout simulation, evaluating
how fast the crew ties the rig to a rescue boat and solve
the problem, minimizing the drive-off time and
consequently the risk of collision.
• Rig inspection – The first inspection occurs at the
beginning of the contract and analogously just after any
system upgrade. All the rigs are also inspected once a
year. The main rig equipment is tested to prevent failure
during operations. Among them, BOP (blow out
preventer), top drive, compensator, power generation,
cranes, etc. The HSE obligations are also audited: safety
equipment and procedures, hygiene, etc.
To avoid interference between units – rigs, lay support
vessel, diving support vessel and stimulation boat – a careful
monitoring routine was established. Every week the schedule
was updated and, sometimes, a conjunction of delay in
operation in one rig and anticipation in another, led the project
coordinator to change the sequence of interventions in three or
four rigs.
To minimize risks of units interference, one rig installed a
new set of transponders with different frequency, allowing her
to travel all over the fields with no chance of bad performance
in the dynamic positioning control.
After the premature failure in one bilateral with gravel
packing, just before the EPC period, an internal workshop was
organized and some important decision were taken aiming at
the reduction of this risk.
• Change four water injection bilaterals in four pairs of
piggyback wells. The prototype of piggyback tree adapter
base was manufactured and available for application in
another well. The estimated costs were similar with less
risk for piggyback completion. New adapter bases were
immediately ordered.
• Two multilateral injectors and one producer became
horizontal wells with longer section.
Special procedures were adopted to reduce the risk of
failure for the remaining two bilateral-horizontal producers to
drill and complete and for the directional to be completed:
Dedicated team. Four months before the first well drilling,
the team started to plan and review the actions for the
execution. The drilling programmer has assumed the rig
coordination and was supported by company men and well
services advisors, all of whom had previous experience in
bilateral construction.
Dedicated rig. An anchored semi was assigned to these
well drillings and completions because of its stability and
lower cost. This rig was not committed with any other critical
intervention so it was capable to absorb eventual delay in
Drill and complete well on paper. The team has
established contingencies for all critical operations and
exhaustedly reviewed the procedures and the well program.
Simple production/injection string. The drive was: “less
accessories implies less risk of failure”. No PDG was installed
to avoid clamps and cables in completions. In case of an
incident, any fish would drop onto junction leading to very
complex fishing job and high risk of premature well failure.
HSE. Besides the KPI monitored during the critical
analysis meetings, a routine of monthly meetings with rig
contractors was implemented. The public discussion of main
incidents and their mitigation led to a “healthy concern”
among the contractors. The daily safety meetings onboard also
contributed for incidents prevention. The rig environment has
plenty of accident risks and only a permanent discussion about
the risks in each phase is able to keep people alert and
consequently reduce LTA.
The good relationship with the reservoir team was one of the
most important key-success factors. During the 3-½ years of
development phase both teams have shared the risks and
together decided the changes in the scope. If one new well leg
were necessary, another one would be reduced or suppressed.
The clear targets for cost and schedule have established a
“cooperation agreement”.
New technologies have played an important role by
reducing risks and allowing the short number of engineers in
the asset to make the best decision during the well
construction phase. Some remarkable solutions were rotary
steerable, at bit sensor, logging-while-drilling, one-trip gravel
pack tools, and piggyback trees and real time monitoring.
The very experienced specialists assigned by the Operator
Well Services to the Project allowed a good planning before
all activities and a fast decision-making when facing
operational problems.
The final cost of each pair of water injector piggy back
wells was equivalent to the planning cost for multilaterals, in
spite of the extra cost for the slave tree. The risk of failure was
dramatically reduced.
The workflow with the service companies has allowed
both teams to focus on solutions and spend no time blaming
each other for undesirable results. The well design has always
been revised twice by both side’s specialists before a final
approval of the drilling or completion programmer.
OTC 17055
Shale intercalations in horizontal section represent
potential risk of failure during sand control assembly
installation. Marl intercalations are acceptable but shale
frequently expands even if using inhibitors in drill-in or
completion fluids, leading to premature well failure. In one
horizontal well, even in the presence of 100 meters of
continuous shale intercalation, the screens assembly was ran
but remained stuck at an expanded shale section before
reaching the final depth and a sidetrack was drilled. After this
bad result, in similar scenarios, the leg with intercalations was
abandoned and a sidetrack was performed with no more than
four days added to the actual schedule.
All of these aspects, allied to management, have resulted in
cost and schedule accomplishment (Fig. 7), a remarkable
performance for the well engineering in deepwater
The authors thanks PETROBRAS for the permission to
publish this paper and the contributions of: Luiz Ignacio
Almeida, Marcos Lopes, Alexandre Pereira, Ricardo Queiroz,
Afonso Pallaoro, Lee King, Rosane Vellasco and Flavia
1. Vilela, A.; Hightower, C.; Montanha, R.; Oliveira, R.; Queiroz,
R. and Pereira, A.; Deepwater Four Zones Selective
Washpipeless Frac-Pack Completion Inside a Bad Cemented
Liner: a Case History; SPE paper 90510, presented at 2004
ATCE – Houston, TX, USA.
2. Alves, Marcelo; Maciel, Walter B.; Reis, Leandro; Braga, Mario
and Marques, João; Campos Basin Tertiary Reservoirs of
Barracuda and Caratinga Fields: Development Strategy and Main
Reservoir Management Issues; OTC paper 17053 - 2005.
3. Juiniti, Ricardo; Pallaoro, Afonso and Ohara, Shiniti – Restriction
Diagrams: How to Work with DP Rigs in Close Proximity – OTC
paper 8852, presented at OTC 1998.
4. Joia, Carlos JBM; Brito, Rosane; Moraes, Flavio; Barbosa,
Benicio; Pereira, Alexandre e Marques, Luiz – Performance of
Corrosion Inhibitors For Acidizing Jobs In Horizontal Wells
Completed With CRA - Laboratory Tests; paper 1007, presented
at 2001 NACE.
5. Nogueira, Emmanuel F.; Saliés, Jacques B. and Fartes, Evandro T.
M. – Slender Well Drilling In Campos Basin. Paper presented at
DOT 2000.
6. Emhjellen, Magne; Emhjellen, Kjetil and Osmundsen, Petter –
Cost Estimation Overruns in the North Sea. Paper published in
Project Management Journal, vol 34 – Mar 2003.
OTC 17055
Figure 1. Barracuda and Caratinga fields
Figure 4. Typical production string and casing for
vertical wells
Figure 2. Barracuda and Caratinga subsea layout
Figure 3. Multilateral targets in Barracuda
Figure 5. Typical production string and casing for
horizontal wells
OTC 17055
Figure 6. Piggyback Christmas tree
Figure 7. Cash flow: baseline, forecast in Dec 2001 and