Corrosion Modeling of Sweet Flowlines Part 2: Applications

Corrosion modeling can be performed very early in project development to estimate the feasibility of carbon steel use. It can also augment many different aspects of the design and operations of sweet flowlines. To achieve this, data used for corrosion modeling must be sourced and attributed to the task in question.

Corrosion Modeling of Sweet Flowlines Part 1: Techniques

CO2 corrosion modeling is a common practice to evaluate carbon steel flowlines and piping, both with and without inhibition, to ensure they achieve their intended design life. Modeling is also used to help determine if a corrosion resistant alloy should be used and can also be utilized to determine corrosion allowance and inhibition requirements.

Pre-Startup Corrosion Prevention: Hydrotesting

Hydrotesting of pipelines and equipment, including tanks and vessels, is a key part of ensuring that they are fit for purpose depending on factors such as contact time, chemicals used, oxygen and bacteria. This may result in general corrosion, crevice corrosion, pitting corrosion, differential aeration corrosion or microbially induced corrosion (MIC). MIC will take place due to the introduction of bacteria during the hydrotesting and/or parking of equipment. Corrosion caused by any one or combination of these mechanisms may reduce pipeline and equipment service life and in extreme cases make it unfit for purpose.

Produced Water Polishing

Produced water systems can be divided into 3 parts including primary, secondary, and polishing, as shown in Figure 1. In earlier GATEKEEPERs, the primary and secondary stages were discussed. Primary treatment is typically done via hydrocyclones or sometimes skim tanks. Secondary treatment is typically done via flotation units. Effluent from the second stage generally meets overboard discharge requirements and the polishing stage is typically not needed.

Produced Water Secondary Treatment Options

Produced water systems can be divided into primary, secondary and polishing systems as shown in Figure 1.

Primary treatment equipment treats water from bulk and other process separation equipment. Effluent from the primary treatment equipment typically contains about 50 to 200 ppm oil with oil droplet sizes on the order of 50 µm.

Secondary treatment equipment is designed to remove approximately 90% of the oil remaining after the primary treatment stage. In a large majority of projects, secondary treatment consists of one or more flotation units. This GATEKEEPER focuses on flotation technology.

Produced Water Primary Treatment Options

Produced water systems are typically designed in stages. These stages are primary treatment, secondary treatment, and polishing. Each stage has select equipment that specialize in the removal of oil and solids from the water.

 

This GATEKEEPER focuses on the primary treatment equipment options for produced water systems. The following primary deoiling treatment items are explored:

  • Skimming Tanks & Vessels
  • Hydrocyclones
  • Voraxial® Separator

Introduction to Produced Water Treatment

As per current regulations, Oil and Grease (O&G) content of produced water (PW) discharged into the Gulf of Mexico (GoM) is limited to a 29 mg/l monthly average with allowable excursions to 42 mg/l. Compliance to regulations has historically been the design basis for produced water treating systems.

Environmental stewardship is now becoming a key priority in the industry, especially among major oil producers. This, together with the inherent uncertainty in the performance of any produced water system, the potential for water soluble organics (WSOs) and some uncertainty in future regulatory requirements, has led many companies to target lower discharge design limits.

Commissioning Lessons Learned—Methanol Systems

Deepwater oil and gas facilities are designed, constructed and commissioned by multiple teams with multiple objectives. Consequently, design disconnects and lack of foresight become apparent during the commissioning and startup phase.

Recent commissioning and startup experiences on an FPSO have provided many valuable lessons regarding such issues. This GATEKEEPER explores how a foreknowledge of design flaws and common discussion would have prevented significant problems seen during the final commissioning and processes startup.

Nitrate Injection Vs. SRU — A Comparison of Operating Costs

In GATE's experience, there are many preconceptions based around the comparative costs of reactive versus proactive souring control strategies. One such area is the comparative operating expenditure (OPEX) associated with the use of either sulfate removal or nitrate injection as part of a proactive souring control program.

Work undertaken to support the development of a recent paper published at the 2011 NACE Corrosion conference by GATE, LLC, and a number of our Clients, included a detailed assessment of the respective operating costs for nitrate injection and sulfate removal unit (SRU) deployment. Although the broader content of the paper considered the comparison of scale squeeze versus SRU use for scale control in deepwater projects, the issues raised by this aspect of the cost analysis are worthy of more detailed comment.

Reactive Souring Surveillance & Control

Reservoir souring is defined as the generation of hydrogen sulfide (H2S) by bacteria in the reservoir following water injection. A number of factors can influence rates of reservoir souring at producers, including, but not limited to, the location of injection and production wells; reservoir geology; formation water, aquifer water and injection water composition; pressure and temperature; biological control in the injection and production systems; and drilling practices. Proactive and reactive souring control methods can be adopted to prevent, control or alleviate SRB activity or H2S production (Note summary to left).

Centrifugal Pump Selection Part 2: Horsepower, Efficiency, & NPSH

In part 1 of this GATEKEEPER series, we discussed how centrifugal pumps work, pump selection criteria as well as the four components of total head (TH), static head, friction head, pressure head, and velocity head. Pump capacity, total head (TH) of the system, horsepower, efficiency and Net Positive Suction Head (NPSH) are all needed in order to accurately size the pump.

In part 2, horsepower, efficiency and NPSH will be discussed which will lead to a final centrifugal pump selection.

Centrifugal Pump Selection Part 1: Total Head

Centrifugal pumps are the most common type of pumps used to move fluids through a system. Centrifugal pumps are used for high flow, low pressure systems. Positive displacement pumps are required for high pressure, low flow systems. In this 2-part GATEKEEPER series, we will discuss how centrifugal pumps work and what information is needed to determine the pump needed for a particular application.