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:
- MPD processes employ a collection of tools and techniques that may mitigate the risks and costs of drilling wells with narrow downhole environmental limits by proactively managing the annular hydraulic pressure profile.
- MPD may increase control of backpressure, fluid density, fluid rheology, annular fluid level, circulating friction and hole geometry, or combinations thereof.
- MPD may allow faster corrective action when dealing with observed pressure variations. This facilitates drilling of what might otherwise be economically unattainable prospects.
- MPD techniques may be used to avoid formation influx, which will be contained safely using an appropriate process.
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:
- washout;
- mud pump problems;
- wells that are statically underbalanced;
- too low mud weight;
- distinguishing a downhole influx from gas (or air) at surface;
- connection gas; and
- trip gas.
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.
|
Download PDF
