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Managed Pressure Drilling
Petrobras is always looking
for new technologies. Since most oil fields are located in deep and ultra-deep
water, exploration costs are very high. Therefore, drilling and completion of
wells in these conditions must always use the best possible technologies.
In order to make new technologies available, Petrobras first checks whether they
are already available on the market. If not, Petrobras normally tries to develop
them in partnership with other operators, service companies, independent
research centres or universities. Several technologies have been developed using
this model.
Here, we are going to describe two technologies that have been developed by
Petrobras in partnership with other companies – managed pressure drilling (MPD)
and intelligent wells.
Managed Pressure Drilling
According to the International Association of Drilling Contractors (IADC), MPD is an adaptive drilling process that is used to control the annular pressure profile more precisely throughout the wellbore. Its objectives are to ascertain the limits of the downhole pressure environment and to manage the annular hydraulic pressure profile accordingly. The benefits of MPD are as follows:
The main objective is to provide the ability to drill a well with accurate control of the bottomhole pressure (BHP), in order that the operation be conducted with more flexibility and in a proactive way; this is in contrast with the passive mode used in conventional drilling. MPD can be described as the sum of mud weight, equivalent circulation density and casing back pressure. With this in mind, it is easy to see that any one of these components can be modified in order to reach the drilling pressure required for the duration of the drilling process.
Several concepts have already been developed and are now being brought to
market. Some of these focus on controlling the equivalent circulating density (ECD),
while others focus on the casing back pressure (CBP). The aim is to maintain a
constant BHP. However, merely having the ability to control the BHP brings very
few benefits if the optimum value to be used is not known. Many of the
techniques and alternatives developed in the past were difficult to accept due
to their complexity, the number of modifications required to traditional ways of
thinking and drilling and the need for substantial investment in equipment and
training. In many cases, the application of these technologies was restricted to
a defined area and problem, increasing the risks involved in making significant
investments.
In order to benefit from the concept of MPD, in early 2006 Petrobras signed a
Technical Co-operation Agreement with Impact Group in order to perform a
four-well evaluation of secure drilling technology.
Secure Drilling™
Secure drilling™ is a closed-loop MPD system based on the microflux control (MFC) method, a new MPD technology designed to improve drilling in most conditions – from simple wells to highpressure, narrow-margin, offshore and other challenging wells – and to increase safety through automated kick detection and control. It uses a closed-loop drilling process that allows for the realtime identification of micro-influxes and losses and the control and management of downhole pressures through automated data acquisition and computerised pressure control. The system is capable of detecting influxes and losses very early and controlling an influx automatically, keeping the total volume of the influx in the well to less than five barrels (bbl). In addition, the system can identify many other common drilling problems, including:
Although the primary objective of Petrobras is to use secure drilling in deep and ultra-deepwater operations, the four-well evaluation programme began with a simple land well before progressing to more complex scenarios. The first well selected for the programme was a shallow exploratory well. A kelly-equipped Petrobras rig without any automation was chosen with the aim of confirming the system’s capability to be used on virtually any rig. The first well was drilled in August 2006 in the northeast of Brazil using a water-based drilling fluid. A total of 1,824ft (556m) of the 81⁄2-inch section was drilled in five days without the system presenting any problems. The results at this first well confirmed the system’s ability to operate in the field under very warm conditions, identify changes in flow on a realtime basis and be installed on most rigs with a minimal number of modifications.
The response from the rig crew was outstanding. They quickly realised the
benefits the system would bring to their daily operation, and the simplicity of
the system, its small footprint and the fact that all operational procedures are
the same as in conventional drilling meant that the rig crew accepted the system
extremely well.
A second well was drilled in November 2006, again in the northeast of Brazil but
this time from a top drive-equipped rig. A total of 6,621ft (2,018m) of the
121⁄4-inch phase and 1,161ft (354m) of the 81⁄2-inch phase was drilled. The
total drilling time was 43 days. During the final phase of drilling the system
detected a 1bbl kick while tripping, allowing for a rapid and safe response by
increasing mud weight. In addition, a micro-leakage at the wellhead was detected
by the system, enabling repair before any major problem ensued.
In the forthcoming months, Petrobras will drill another two wells using the
secure drilling method – one in an onshore tight-gas scenario and the other in a
high-pressure, high-temperature (HPHT) well from a jack-up rig.
Intelligent Wells
A well is called
intelligent only if it adds value to the project during its life-cycle.
Monitoring of production parameter elements and/or flow control devices are used
to determine this.
Subsurface monitoring gained popularity in the early 1990s due to an increase in
reliability and the improvement of metrological parameters. This has accelerated
the development of optical technology, which has been made more robust in order
to survive hostile environments such as downhole conditions. Petrobras is
investing in the development of optical sensors as well as downhole flow control
for moderated service conditions. These areas have seen significant results,
e.g. the Carmopolis intelligent field project (see below). At present, this is
the main application of intelligent wells in Petrobras, resulting in a more
efficient use of human and material resources.
The definition of ‘intelligent completion’, according to the White Paper on
Digital Oil Fields of the Future (DOFF) by Cambridge Energy Research Associates
(CERA), is completion using downhole sensors and remotely actuated flow control
devices, allowing access to realtime information and supporting fast decisions.
The use of permanent downhole monitoring systems in oil and gas wells began in
the late 1960s, but it was only in the early 1990s – when reliability reached
acceptable levels and metrological parameters were improved – that it was widely
adopted by operators. The use of quartz sensors and improvements to the
robustness of electronic sensors were responsible for this evolution. In the
late 1990s, optical fibre sensors began to be used, with a focus on improving
reliability and ensuring the simplicity of technological updates. These sensors
have played an important role in the high-flow gas wells of HPHT wells.
Among the sensors available on the market, the distributed temperature sensor
(DTS) and the pressure and temperature (P&T) sensor are the most common. Sensors
play a major role in intelligent wells as they provide the operator with a
realtime perception of the production process.
Intelligent completion packers are used to provide hydraulic isolation of each
zone, allowing selective control of the intervals; the uppermost completion
packer is also responsible for anchoring the tubing and providing the first
safety barrier for the annulus – the same basic functions of a regular
production packer. Furthermore, there are packers for isolation purposes only;
as these include only the isolating material with no anchoring material the
force needed to unset them is reduced, allowing a large number of isolation
intervals. The intelligent completion packers also include passages for the
control and monitoring lines, known as ‘penetrations’; typically, an intelligent
completion packer presents four to nine penetrations. During setting procedures,
the intelligent completion packer must not allow its components to move to avoid
transmitting any tension to the control or monitoring lines.
The flow control valves are responsible for allowing selective control of
production or injection. They can be actuated hydraulically or electrically, or
by a combination of both (multiplexed). Hydraulic actuation is the most common
type; here, a balanced piston is used to shift a sliding sleeve that restricts
the passage through the valve. Usually, one opening control line is used for
each valve with a common closing control line for the system to reduce the
number of hydraulic lines installed. In electrically actuated valves, an
electrical motor is responsible for the shifting of the sleeve. The motors are
actuated using a single electrical line for all motors that also supplies the
addressing information, which is decoded in the valve. This makes this kind of
valve appropriate for wells where there are restrictions on the number of
penetrations on the wellhead or on the tubing hanger.
The valves can also be
classified according to the flow control they provide – on-off, multi-position
and infinitely variable. On-off valves provide selectivity simply by allowing or
not allowing the flow. Multi-position valves provide several steps of choking
and are designed according to the flow rate expected in the well. They can use
an index system to restrict the course and supply choking or an external device
that provides a very controlled volume of hydraulic fluid in each shifting.
Infinitely variable valves are more complex, as they require sensors to give
feedback on their position in order to adjust the choking. There are also
several geometries for the valve orifices – the most common are circular and
elliptical slots, which are used in on-off/multiposition and infinitely variable
valves respectively. The main parameters for specifying intelligent completion
valves are flow range, maximum pressure and maximum differential pressure.
When using hydraulically actuated valves, an hydraulical power unit (HPU) is
needed. Basically, an HPU comprises a pump, which can be pneumatic or
electrically actuated, and a manifold, which is manipulated according to a logic
determined by the maker of the system. This logic can be placed in a
programmable logic controller (PLC) that actuates solenoid valves on the
manifold, making the entire procedure transparent to the operator, as well as
providing the ability to operate the HPU remotely. To confirm shifting,
intelligent completion HPUs usually have a small tank that verifies the volume
of fluid returned after the pressures supplied to the valves have stabilised.
Some HPUs also measure the flow rate of the returned fluid, but this process is
much more complicated and significantly increases the cost without providing
many benefits.
The cables used for monitoring and control have to be protected against
chemically hostile environments, such as downhole conditions and mechanical
shocks during intervention procedures. Generally, the conductor medium
(electrical or optical) is encapsulated in a 1⁄4-inch metallic tubing – which
offers mechanical resistance – and coated with a polymeric material – which
protects against chemical attacks. Cable protectors (clamps) are used to hold
the cable to the production tubing and to offer extra protection near the
couplings, where the diameter of the tubing is increased. Dry-mate connectors
are used to connect the cable to sensors or to another cable. Devices called
‘feed-throughs’ are used to pass the signal through the tubing hanger and
wellhead and ensure that there is no pressure communication. In subsea trees or
downhole, wet-mate connectors are used in seawater environments or in the
presence of production fluids.
A range of electrical connectors – both dry- and wet-mate – and feed-throughs
are already certified and used by Petrobras; optical dry-mate connectors and
feed-throughs are currently passing through the certification process; while
optical wet-mate connectors that match Petrobras specifications are still at the
development stage.
The data gathered by the sensors need to be presented to the operators in
realtime, which can be achieved using a supervisory. It is also very important
that the connectivity of all equipment allows the integration of all data. The
use of open standards and protocols reduces connectivity and integration issues.
Intelligent completion can be used together with other completion techniques
such as sand control and artificial lift, but in these cases an interface
project is crucial to ensure the reliability of the system. Specific completion
tools or projects are used to integrate artificial lift systems with intelligent
completion, allowing the intervention of the upper tubing – which contains the
lift system – to be independent from the lower tubing – which contains the
intelligent completion tools. These tools include a wet disconnect tool (WDT),
which is the most practical solution for completions using electrical
submersible pumps (ESPs). Electric-hydraulic and optical-hydraulic WDT tools are
currently being developed by Petrobras in conjunction with service companies.
Value Chain
Several aspects regarding
the use of intelligent wells need to be analysed. Permanent monitoring allows
reservoir management to be optimised. The selectivity achieved by flow control
allows formation and interference tests to be carried out more simply, and more
precise data to be obtained with a view to updating reservoir models. The data
obtained can also be used to minimise water production, reducing the need to
process for re-injection and disposal and thus reducing the size of the plant.
Distributed temperature monitoring can be used to optimise and evaluate steam
injection and gas lift. Monitoring the pressure and temperature of the pump
inflow allows automatic adjustment of pumping parameters. Surface or subsurface
data can be used for early prediction of faults in processes and equipment
through pattern recognition techniques such as neural networks and data mining.
Realtime monitoring allows precise fault diagnostics, allowing better use of
human and material resources.
As with any tool, an economic and value-added evaluation must be used to
estimate all of the benefits. The operational impact of the equipment must also
be evaluated due to its quantity and complexity. There are several endeavours
both inside and outside Petrobras working to create analysis tools that support
intelligent well projects, which will help operators to choose the most
appropriate solution.
Applications in
Petrobras
Land Mature Fields
Petrobras chose the
Carmopolis field, a land mature field, as its first intelligent field pilot
project. As seen in Figure 3, the project encompassed seven wells equipped with
intelligent completion, using different suppliers. The intention was to identify
the suppliers that had solutions for moderated service conditions such as those
found in Carmopolis.
An integrated intelligent well system was developed for the project. In this
system, artificial lift automation was completely integrated with the
intelligent completion system in order to satisfy the availability and
reliability demands of the operators and to ensure that the benefits of the
reservoir and production optimisation were effective.
The well completion consisted of three hydraulic packers, three flow control
valves and four pressure and temperature optical fibre sensors. The equipment
was developed to be low cost with moderate service condition specifications. The
artificial lift method used in the project was a rod pump and the regular
practices were to locate the pump below perforation and to use fixed pumps. A
completely new automation system was used to integrate all systems using open
standards and remote diagnostics ability.
Although the conventional well completion used in the Carmopolis field was very
simple and had a low intervention cost, the large number of wells (more than
1,000) elevated the maintenance cost of the field. Also, being a land mature
field, a large number of interventions were needed – mostly to change artificial
lift equipment and to increase productivity – requiring a large number of rigs
to maintain the field. The operation had a very limited budget due to its low
productivity and a very limited number of rigs available to make the
interventions.
The initial results from the Carmopolis project showed improved reliability,
diagnostics and capital expenditure (CAPEX) when compared with similar
implementations in Petrobras. The expectation from this point forwards is that
operational expenditure (OPEX) will also be improved.
Conclusion