An experienced technician from conventional onshore fields entering a pre-salt project for the first time quickly realizes that the process parameters don't fit the same instruments. The design pressure can double. The materials for wetted parts that worked well in the conventional field become out of specification. A sensor installed without attention to fluid composition can fail within months, even operating within the nominal range.
The issue isn't difficulty—it's category. The pre-salt layer represents a distinct environment, with combinations of pressure, temperature, salinity, and acidic gases that activate failure mechanisms nonexistent in conventional fields. Therefore, understanding where these two worlds diverge is the basis for any safe instrumentation specification for pre-salt and conventional fields in oil and gas.
Two environments, two categories of requirements.
O conventional oil Whether onshore or offshore in shallow water, the industry operates within parameters it has managed for decades. Reservoirs between 500 and 3.000 meters deep, pressures from 100 to 400 bar, and bottomhole temperatures between 60°C and 120°C. These are challenging conditions, but with established standards, standardized catalogs, and extensive operational history.
The Brazilian pre-salt layer, especially in the Santos Basin, operates on a different scale. The reservoirs lie beneath a layer of salt up to 2.000 meters thick, under water depths reaching 2.200 meters. Therefore, the pressure at the bottom of the well exceeds 700 bar in several fields. The reservoir temperature surpasses 150°C in certain formations, and the fluid composition is rich in CO₂, with a high concentration of salt and, in some areas, H₂S: conditions that conventional materials cannot withstand.
Depth and pressure: the first divider
No parameter impacts instrumentation specifications more directly than design pressure. In conventional fields, transmitters with a range up to 400 bar and ANSI 900# flanges meet the needs of most applications.
In the pre-salt layer, the static pressure of the column combined with the reservoir pressure may require instruments with a test pressure above 1.050 bar. This changes the equipment architecture:
- Flanges are upgraded to ANSI 1500# or 2500#, or converted to special bend connections (SPM type).
- Isolation valve bodies require recertification for sour service according to NACE MR0175/ISO 15156.
- Transmitters will now be specified with a Hastelloy C276 diaphragm or higher.
- Thermowells require stiffness calculations according to ASME PTC 19.3 TW-2016, using duplex or superduplex material.
One point that specifications often ignore is cyclic fatigue. In the pre-salt layer, therefore, pressure variations during production subject the instrument to repeated loads that accelerate the failure of diaphragms and welded connections. An instrument sized for maximum pressure, but without pressure cycle traceability in the design, can fail prematurely, even within the nominal range.
Temperature along the production column
The reservoir temperature in the pre-salt layer is, by itself, high for conventional instrumentation. However, the main problem is not the maximum value: it's the thermal gradient along the well.
In pre-salt wells, the reservoir temperature can reach 150°C, while at the wellhead, 2.000 meters deep in water at 3–4°C, the temperature drops to less than 10°C. This gradient generates cyclical mechanical stresses on sensors installed in the pipeline and imposes insulation requirements that do not exist in onshore applications.
To thermocouples and RTDs Installed in FPSO (Floating Production Storage and Offloading) units, temperatures are milder. Even so, the presence of light hydrocarbons with high vapor pressure requires that each penetration in the process be made with double insulation and a connection tested by hydrostatic pressure, independent of factory certification.
The IEC 60079 standard and ATEX or IECEx certification are basic requirements for any electrical instrument in classified oil and gas areas. In the pre-salt layer, the high concentration of CO₂ can alter the zone classification and, therefore, require a review of the previously specified protection rating.
Salinity and acid gases: the problem of corrosion.
The salt layer that characterizes the pre-salt layer is not just a geological marker. It directly affects the composition of the produced fluid: pre-salt oil rises mixed with formation water with salinity far exceeding that of conventional seawater. In some areas, the concentration of chlorides in the produced water exceeds 200.000 ppm.
This level of chlorides, combined with temperatures above 100°C, makes 316L stainless steel unsuitable for wetted parts due to the risk of chloride stress corrosion cracking (CSCC). The minimum specification becomes duplex 2205 (UNS S32205). For services with confirmed H₂S, the choice falls on superduplex 2507 or nickel alloys such as Inconel 625 and Hastelloy C276.
The NACE MR0175/ISO 15156 standard defines the material selection criteria for sour service. In E&P contracts in Brazil, compliance with this standard is a contractual and traceable requirement. Any instrument specified without verification against it represents a risk of non-conformity in inspection—not just operational performance.
High-pressure CO₂, in turn, forms carbonic acid upon contact with produced water and attacks metallic surfaces through galvanic corrosion. CO₂ corrosion rate models, such as DeWaard-Milliams or Norsok M-506, are references that the specifier should, at the very least, request from the process supplier before finalizing the instrument's specifications.
Materials and specifications: a practical comparison
| Parameter | Conventional Oil | Pre-salt |
|---|---|---|
| Typical design pressure | 100–400 bar | 400–1.050 bar |
| Process temperature | 60-130 ° C | 80-180 ° C |
| predominant flange class | ANSI 600–900# | ANSI 1500–2500# |
| Minimum material (wet parts) | SS 316L | Duplex 2205 / Superduplex 2507 |
| Sour service (H₂S) | Occasional | Frequent — NACE MR0175 required |
| CO₂ content | Low | High — corrosion rate calculation required |
| Electrical certification | ATEX/IECEx Zone 1 or 2 | ATEX/IECEx Zone 0 or 1 |
In addition to material specifications, traceable documentation becomes part of the delivery. Projects requiring an Inspection and Test Plan (ITP) demand a material certificate (MTR) with batch traceability, a dimensional inspection report, a hydrostatic test certificate, an INMETRO/RBC traceable calibration certificate, and, when applicable, a declaration of conformity with NACE MR0175.
How to specify instrumentation for pre-salt and conventional oil
Specification begins before instrument selection. Four questions guide the right direction:
What is the maximum allowable pressure in the line (MAWP)? Not the normal operating pressure, but the worst-case process scenario plus safety valve overpressure.
Is the service sour? The presence of H₂S above 0,0003 MPa partial pressure activates NACE MR0175. Even trace concentrations need to be checked against the standard limits.
What is the composition of the water produced? The combination of chloride content, pH, and temperature defines the risk of CSCC (Contains-Complexion-Coefficient of Carcinoma) and, therefore, guides the selection of metal alloys.
Will the instrument be located in a classified area? If so, what is the zone, gas group, and temperature class? This defines the required electrical protection certification.
With these answers in hand, the specifier eliminates most unsuitable instruments before opening any catalog. What remains is to evaluate the measurement performance (accuracy, repeatability, response time) within the options that passed the mechanical integrity filters.
Alutal technical support for O&G
Since 1994, Alutal has manufactured temperature sensors with specifications for harsh environments. For oil and gas projects, the product line includes thermocouples and RTDs with superduplex sheaths and nickel alloys. thermometric wells Calculated according to ASME PTC 19.3 TW-2016 and assemblies with ATEX/IECEx certification.
The Alutal team of specialists assists in specifying data based on the client's process (pressure, temperature, fluid composition, area class) and issuing traceable documentation for ITP projects.
For applications in pre-salt or sour service instrumentation, contact Alutal and describe your process parameters. The technical team provides support from material selection to specification review before issuing the purchase order.
