Common Pitfalls During Subsea Cathodic Protection Design

For most offshore facilities and subsea components such as trees and manifolds, carbon steel is a common material of construction. Effective external corrosion control is essential for the longevity and safe operation of these components.

For long-term external corrosion protection of subsea steel components, cathodic protection (CP) along with corrosion coatings are commonly used. As the offshore environment moves into deeper waters, the cost of interventions subsequently increases. Therefore, the engineer is challenged with balancing a highly reliable CP system, sometimes achieved with excess anode mass, with CAPEX and weight restrictions. The optimal CP system will need to minimize weight and cost and maximize reliability.

Ballast Tank Water Treatment

SPAR hulls and other floating production facilities may require temporary ballasting with seawater during transportation from the hull construction site to the integration location. Ballast water tanks may be completely or partially filled with seawater in this case, where some tanks may remain filled for the life of the asset and others will be drained and left dry once the installation process is complete. Seawater often contains significant concentrations of bacteria, which can cause corrosion when the seawater remains inside the ballast water tanks for extended durations.

Placement of Sulfate Removal Units in Waterflood Systems

Deepwater seawater injection projects, whether subsea or dry-tree developments, generally face the dual challenge of scale control and reservoir souring. These challenges are such that practically all deepwater seawater injection projects are forced to adopt a proactive approach that considers the options of designing for production well scale squeezes or applying sulfate removal for scale control and the use of either nitrate injection or sulfate removal for souring control.

Sulfate removal units (SRU) are able to reduce the sulfate content of injected seawater by filtering the water prior to introduction downhole. 

Control of Flow Rates at Startup

Either by nature, or by training, engineers are conservative. That is generally a good thing, but we sometimes go too far. For example, chokes and control valves are often oversized even for normal operation, and are sometimes far too large to provide adequate control of low flow rates at initial startup. Startup planning should include an assessment of the operability of chokes and control valves.

 

Five different conditions exist for flow through restrictions:

  1. Liquid flow
  2. Non-critical gas flow
  3. Critical gas flow
  4. Non-critical two-phase flow
  5. Critical two-phase flow

A More Effective HAZOP Process

A group of subject matter experts gather together to evaluate a design; for a plugged-in engineer, nothing is more fun than that! Yet HAZOPs are boring and exhausting for most people. That’s wrong! HAZOPs should be fun!

Picture yourself leaving a HAZOP exhausted, but hoping you can attend another one soon.

The Problems with HAZOPs

HAZOPs are not as effective as they should be. Duhon and Sutton (2010, SPE 120735) identified many reasons why we don’t learn as much as we should from HAZOPs. These insights suggest a path towards a more effective HAZOP Process.

Use and Selection of 13Cr Steels

Of all the corrosion resistant alloys (CRA) used in oil and gas developments, martensitic stainless steels (MSS) are some of the most common. These steels not only have the advantages of normal steels: high strength, cost effective, easy to manufacture, available in a wide variety of product forms, but they also have good CO2 corrosion resistance at higher temperatures as a result of their 11% minimum chromium content. One of the most common types of MSS used in the oil and gas industry is 13% chromium steel. NACE and API standards both reference several different varieties of 13 chromium steels for use in oil and gas projects.

Chemical Compatibility Considerations

Production chemicals that are used in the process system offshore vary in configuration, carrier solvents, type, viscosity and performance. These can be based on a range of inorganic, organic, simple, complex and polymeric chemicals. As such, they have different fluid characteristics and respond differently to pressure and temperature. The compatibility of these chemicals, both with each other and with the production system as a whole, is a critical consideration when selecting fit for purpose products to support production operations.

Subsea Raw Water Injection

Water injection is often an integral part of the field development plan adopted for subsea developments, where projects may not be economically viable in its absence. However, a significant drawback to the use of topsides water injection facilities for offshore developments is the weight and space required for equipment. As outlined in Figure 1, this can typically include pumps, filter packages, deoxygenation and sulfate removal units. These limitations become particularly problematic for retrofit systems with limited design flexibility and for floating production platforms where weight and space are often tightly limited. A relatively recent development has been to move the water injection equipment away from the topsides and to place it subsea.

Keys to a Successful Initial Startup

Deepwater oil and gas facilities are designed, constructed and commissioned by multiple teams with multiple objectives. Effectively managing those interfaces is important in every phase of the project and critically important at Initial Startup. The Initial Startup is the moment of truth where everything from subsurface to topsides becomes a single entity and has to work together. Design disconnects will become apparent. Also, the Initial Startup phase is transient in nature, which presents significant challenges. Careful planning will minimize many of the risks that may arise. This article provides a set of suggestions for planning the startup of a deepwater oil and gas facility in an effective and efficient manner to ensure a smooth transition from Final Commissioning to Initial Startup and Operations exists.

Induced Gas Flotation - A Unit Operations Perspective

Permitting of new and existing offshore Gulf of Mexico discharges related to oil and gas exploration and production are regulated by EPA Region 6 under the National Pollutant Discharge Elimination System (NPDES) general permit number GMG29000. This NPDES permit establishes an oil limitation of “29 mg/L average” with a “42 mg/L maximum” limit on oil and grease as measured by the hexane extraction/gravimetric method (EPA Method 1664A).

Although these discharge limits are unlikely to change anytime soon; as good corporate citizens and environmental stewards, our industry continually strives to improve the design and performance of produced water treatment systems. In addition, many operators have implemented more stringent internal standards than the permitted levels of oil and grease.

Flexible Pipe for Sour Service

The offshore use of flexible pipe in oil and gas production has been steadily increasing since first used in the 1970’s. Initially used in North Sea and North Slope applications, the use of flexible pipe is beginning to expand to other locations as new fields are discovered in ever more challenging locations. In particular, the expansion of the industry into deeper waters has been accompanied by the need to accommodate demands such as higher operating temperatures and pressures, higher carbon dioxide (CO2) and hydrogen sulfide (H2S) acid gas concentrations, different completion and acidizing fluids, and water injection. One of the most significant challenges is that materials exposed to H2S need to be qualified for sour service. Metals are often limited by their yield strength or hardness and any welds in H2S, and polymers are limited by H2S permeability and degradation resistance.

Chemical Injection Rate Control Valves

IRCVs can be effective in deepwater. Successful application requires a systems approach and incorporation of lessons learned. The conventional approach to injection of production chemicals is to use a separate pump for each injection point. For topsides injection at low to moderate pressures these systems are small and inexpensive. But in deepwater they can be large, heavy and expensive. A common alternative is to use distributed delivery systems featuring Injection Rate Control Valves (IRCVs) to control flow to individual locations. IRCV systems are cheaper, lighter, smaller and more flexible.

But many operators have little faith in them. Some IRCV installations have failed and some have worked only after significant effort. Many things can go wrong. Most engineers designing these installations are not aware of all the design requirements, and vendor literature typically does not provide adequate design guidance.