PRODUCTION

How to analyze / handle tubular corrosion problems

There are several ways an operator can plan for tubing-string corrosion. Example analyses show how to select the most profitable approach

G. R. "Bob" Moe, P.E., and Carl K. Johnson, partners, Viking Engineering, L. C., Houston

ow should an operator handle the questions of corrosion and the available approaches to mitigation? The authors’ company is frequently asked to participate in the critical debate regarding which approach is most suitable for a specific well. Should the tubing string be batch-treated with chemical inhibitors? Will continuous corrosion inhibition justify the plumbing required to implement this scheme? Are corrosion-resistant alloys (CRAs) the answer?

Just let it rot and replace as necessary should always be considered as an option. Frequently, the chosen direction is to just do what was done on the last well in the area. Often, the most important first step in resolving this debate is completely overlooked. Economics should drive the answer.

Viking Engineering presents an approach that allows the production engineer to utilize field data and costs to develop comparative economics. Inhibitors and their cost of application, including well downtime and lost production, are compared to continuous inhibition facility costs and the large-upfront-cost CRAs. An example of the process, complete with comparative economics and system cash flow discounted for the cost of money, is included.

Imagine yourself as a production engineer, completing the deepest, highest-pressure well in your area in years – and a DST confirms it is a success! This new well could be the number one producer for the whole division. With all the management attention drawn to this well, this is your opportunity to equip it properly. You surely do not want to see corrosion raise its ugly head in this career-boosting story, nor do you want to squander that precious O&M budget.

Should you outfit the well with CRA tubing? Batch treatment may not be 100% effective at the depths and temperatures involved. Continuous treatment requires the use of capillary tubes. Maybe it will be cheaper to replace the tubing after a few years. Management wants a solid technical recommendation – and soon. The following discussion addresses this dilemma, giving positive analyses showing that the most effective / economic way to keep the well producing is the best approach.

Economic Model

Operations and engineering groups alike often jump to the conclusion that whatever corrosion mitigation scheme was chosen for the last well in the area is appropriate for the next well. However carefully engineered at the time, the previous well is not the same as the new well. Payzones get deeper, sands become drawn down, faults get crossed, and fields go sour with extended injection projects. Even within a limited geographical area, selecting the optimum corrosion mitigation scheme is a moving target.

The responsible engineer – whether he or she hails from production, subsurface, or drilling – is often pressed to implement a corrosion-mitigation plan in real time along with a profitable depletion plan. The choices are driven by management, field operations and timing. The top priority – economics – is often lost in the shuffle.

For most operators, the full slate of mitigation schemes to be considered is limited to four. Even at the point at which production is initiated, many unknowns exist and costs or profitability may seem uncertain. Comparative economics emphasize the differences between the schemes evaluated, and deemphasize those features which may cancel in comparison.

No attempt has been made here to address a full economic model with taxes, royalties, field operating costs, or product transportation. The example details a deep, high-pressure, South Texas gas well with 12% CO₂. The corrosion conditions are severe, but not unusual for the region. Four completion and operating scenarios are considered to objectively evaluate the comparative economics. These are:

1. Do nothing – Run tubing and produce the well with no inhibitor and suffer the consequences. Doing nothing should always be considered an option. Short-term wells may be in a position to deplete beyond economic limits prior to unmanageable or expensive corrosion problems. It may be cheaper to simply replace a corroded tubing string rather than take steps necessary to make it last. For the example, this approach is not seriously considered. Workovers are too frequent and interruptions in production are too costly.
2. Batch treatment – Run tubing and treat once per month with corrosion inhibition chemicals, allowing for one day per month to be lost to treating operations. Batch and fall techniques followed by bringing the well back on production will not result in 100% coating efficiency and some corrosion or pit advancement is modeled.
3. Continuous treatment – Run tubing with 1/4-in. or 3/8-in.-dia. capillary tubing, anchored to the outside of the string or suspended down the inside of the tubing. The exterior configuration takes planning regarding clearances with casing and extra care during running operations. The recommended treatment volume is pumped down the capillary tube each day, often to a port in the packer. Pump, tubing and modifications to packer and wellhead are all required. The interior tube approach may not require all the hardware modifications, but the capillary tube must be removed prior to any wireline or coiled-tubing intervention.
4. CRA tubing – Run corrosion-resistant-alloy (CRA) tubing suitable to resist the initial conditions. CRA properly matched to the producing environment may circumvent any corrosion concerns. Well stimulations, acid jobs and scale buildup are often ignored during CRA selection. Used strings of CRA tubing can represent significant savings as long as they have not been abused. Significant salvage value can be realized after the well’s depletion. CRA will initially be the most costly option, but may be the most cost effective when evaluated over the well’s life.

Example Well

Viking has had the opportunity to set up comparative economics for a variety of prospects. While the technique may be best suited to "big picture" or field applications, it can also be applied to individual wells. The example well is a 16,000-ft, corrosive-gas well in South Texas. Specific well data includes the following.

Gas rate = 0.6 to 15 MMcfd, based on commingling of zones and depletion. Several series of zones were on the depletion schedule resulting in relatively high rates until those zones were partially depleted. Adding new perforations and commingling a number of zones is common practice in South Texas and presents an additional challenge for the well designer. Just when rates and pressures taper off (in Year 5 or 6), new zones are added and design loads are much like they were in Year 1.

Erosional velocity, related to the rate at which the tubing is actually produced, should be considered, as it could push material selection beyond carbon steel. High-rate wells can give inhibitor coatings problems for much the same reason, as the inhibitor must stay on the pipe surface to mitigate corrosion. Gas velocity at 15 MMcfd does not exceed filming rate or the ability to coat the tubing with inhibitor. Carbon steel is generally resistant to the mechanical impact of product flow up to 40 fps. Thus the example well is not threatened by erosional velocity.

H₂O rate = 30 to 80 bbl/MMcf, increasing throughout well life. An over simplification of the role of water in a well such as this example leads to several generalizations: 1) no water; no corrosion; 2) more water is more corrosive; and 3) there is no such thing as perfectly dry gas. There will always be some water carried in solution or as a mist.

The flowstream from the deep, hot well chosen for our example cools as it approaches the surface, and liquid water condenses on the inside surface of the tubing. Liquid water and CO₂ form a powerful carbonic acid, one of the most aggressive corrosion foes.

Treating expenses. Batch-treat expenses are $72M/yr ($72,000) for Years 1 – 5, and $24M/yr thereafter. Pitting corrosion requires a workover in Year 6. The batch treatment prior to the workover includes the cost of a high-pressure pump truck. The model used assumes that the sand formation is perforated and commingled after the workover and can be treated without the pump truck at $24M/yr. Pit advancement continues, so well life is a factor.

Continuous inhibition is modeled at $12M/yr. Estimates are available from local treating companies. Continuous treatment can be effective and economical after the capillary tube and associated hardware are installed. As the operational considerations of long 1/4-in. or 3/8-in. tubes will vary well to well, so will the attractiveness of continuous inhibition. The example well is outfitted with $3/ft capillary tubes and a $13M investment in surface pumps, hanger and packer modifications. Total upfront hardware expense is $58M.

Lost production, other considerations. Often ignored in economic comparisons, is the impact of downtime or no production for the given inhibition and production scheme. Each approach has its downside and these must be taken into account when generating an economic model. Whether lost or deferred, interruptions in production will have an economic impact.

Batch treatment requires the well to be shut-in, the inhibitor pumped down the tubing and some amount of time alloted for the inhibitor to fall. Distribution of the chemical takes place as the well is brought back on, and any difficulty in reestablishing production should be built into the model. No inhibition treatment will stop corrosion, but a properly designed chemical can slow down the process. The example carries a pit growth of 0.035 in./yr despite batch treatment.

Continuous treatment relieves the need to shut-in the well periodically. Impact on the production schedule should be minimal. Pit growth due to CO₂ corrosion is assumed to be 0.004 in./yr.

Corrosion-resistant-alloy installations require no chemical treatment and therefore no associated downtime. The CRA scheme will recover high upfront cost of the alloy. Salvage value will also help in this regard. Tubing is assumed to be L-80, priced at $0.60/lb, except in the case of CRA. The operator was fortunate enough to find suitable CRA on the ground at $80/ft. Salvage value is estimated at 50% at the end of the project.

Table 1 shows the relative profitability for the four scenarios. As is shown, continuous treatment and utilization of CRA tubing compete for most profit. Experience has shown that, depending on well conditions, it is not at all uncommon to generate the highest profitability by installing CRA. In doing so, the lowest amount of intervention is required. Table 2 provides the detailed calculations for the four mitigation methods.

Example-well conclusions. The focus is on the "discounted income" figures generated at the lower right-hand side of each segment of the table. Bear in mind that these are comparative economics and have little value outside the context of this particular evaluation. Using a discount rate of 10%, the batch, continuous and CRA scenarios all compete closely at $16MM (million $). The do-nothing approach ($7.2MM) suffers from downtime and lost production. This example well may be most profitable with the use of continuous inhibition. Without a doubt, the most important factor in achieving a profitable well is to keep the well producing, utilizing any corrosion scheme necessary.

The authors
	G. R. "Bob" Moe, P. E., partner at Viking Engineering, L.C., earned a BS in civil engineering in 1975 from South Dakota School of Mines and Technology. His consultant role with the firm includes well design, planning and quality assurance for HTHP oil/gas wells, a Viking specialty. His 27 years of experience include drilling and subsurface responsibilities with a major producer, and pivotal consultation in major project planning, scheduling and coordination.
	Carl K. Johnson, partner at Viking Engineering, received his degree in PE from Marietta College in 1967. He has over 30 years of broad experience in all aspects of oil/gas industry well engineering and operations. His consultant role with Viking includes well design, planning and quality assurance for technically complex oil/gas wells. Prior to Viking, he held a variety of engineering / management positions with major and independent producers. He is a member of SPE.