What's new in production: Banking crisis

LEONARD KALFAYAN, CONTRIBUTING EDITOR

One of the worst things to hear or read about in our daily lives is that a banking crisis is imminent, or worse, that a banking crisis has occurred. The economic consequences of a banking crisis, if not addressed preemptively or in time to limit the damage, are numerous and dire, and need not be detailed here.  

Just the same, condensate banking in a gas well can also become a productivity and economic crisis, if ignored or not properly addressed proactively. Unfortunately, condensate banking in gas wells is a problem often considered to be irreparable and something that just has to be lived with until affected wells become uneconomic to produce. But, in fact, there are technologies and methods that can treat condensate banking, and at least reduce its longer-term effect, thereby avoiding premature well failure that results from a condensate banking crisis.  

In gas wells, a bank of condensate can rapidly build up in the near-wellbore formation region, when bottomhole flowing pressure falls below the dewpoint. Furthermore, this bank grows deeper into the formation as reservoir pressure declines, reducing relative permeability to gas, impairing overall well deliverability, and acting as increasing skin damage. A complication that is not so uncommon is that increasing skin, due to condensate banking, is misdiagnosed and thus is not addressed properly. Production declines, due to condensate banking, can have the same profile as wax or asphaltene deposition, or fines migration. Therefore, treatment with hydrocarbon solvent for organic deposition, or with acids for fines migration in a sandstone formation, may only result in minimal improvement, if any at all.  

As mentioned, there are methods for treating condensate banking, but all have their limitations. Those most commonly employed are summarized below. Some act to reduce near-wellbore pressure drop to prevent condensate “drop out,” while others serve to alter wettability or reduce interfacial tension between gas and condensate, such that the banking condensate is induced to flow out of the well more readily, depleting the volume of the bank. Common treatment methods are summarized below.  

Alcohol injection. A reasonable but temporary treatment to reduce condensate banking is with injection of alcohol into the gas / condensate producing well. Methanol is most common, but other alcohols, such as isopropyl alcohol (IPA) and special alcohol blends, also can be used. Alcohol reduces the interfacial tension between gas and condensate. Significant improvement is possible, depending on how severely the condensate bank has built up. But treatment with alcohol is typically a very temporary fix when it is effective, and methanol is not desirable to handle on site.  

Hydraulic fracturing. Fracturing to reduce the propensity for condensate bank occurrence is not always an option. For example, in offshore wells that are completed with frac packs and sand control screens, refracturing is not possible. But in onshore wells, fracturing can often be an option and can be an effective method. The idea is that creating a fracture, even with a relatively short length, can reduce drawdown enough to prevent condensate dropout and development of a bank for a period of time generally longer than that which can be achieved with a matrix treatment with alcohol or other fluids (e.g., acids). But once the dew point is breached, condensate begins to bank, and now within the fracture or fractures created. When that happens, treating for removal or reduction of the bank can be especially challenging, as the bank may now extent much deeper in the reservoir.  

Acidizing is not a direct method for condensate bank removal. In a sandstone, hydrofluoric (HF) acid treatments are conducted to remove fines plugging in the matrix formation and/or in perforations. Reducing skin damage, due to fines and increasing gas flow capacity in that manner, may indirectly reduce a condensate bank when present but not likely to a significant extent and in any case, only temporarily.  

However, in a carbonate reservoir, in which hydrochloric (HCl) acid or other acids or chemistries can dissolve carbonate rock—forming channels—condensate banking can be reduced more realistically. With the formation of channels with acid or reactive fluid, pressure drop is reduced, thereby reducing condensate dropout. This is similar to the reduction in condensate banking with hydraulic fracturing, but instead, this is done through the creation of multiple, dissolved channels in the carbonate formation.  

Wettability alteration. Injection of a solvent containing a surfactant that is gas-wetting or non-wetting can increase the relative permeability to condensate, thereby reducing the extent of a bank, and even more permanently maintaining a reduced bank, as long as the surfactant remains adhered to the treated formation surfaces. Such surfactants also can be introduced to the formation in conjunction with alcohol injection or in acid treatments. Surfactant effectiveness diminishes with high reservoir temperatures, though, and many gas / condensate wells are completed in high-temperature formations (greater than 250^o to 300^oF).  

Non-surfactant wetting agents, such as nanoparticles, also can be applied, including at higher temperatures, but in tight gas formations, nanoparticles may cause physical flow restrictions in the very small pore spaces. But in higher-porosity and -permeability formations, there are nanoparticles that can favorably wet the rock to induce greater condensate production relative to gas production and reduce the size of the bank and the impairment to gas production rate caused by the bank. 

Gas injection. A common, and reasonable, temporary treatment method for mitigating condensate banking is via huff-and-puff injection of gas into the producing well. Injection of gas can increase pressure above the dew point, thereby reversing the condensation process, and removing or at least reducing the condensate bank. Nitrogen gas injection is the easiest option. CO₂ gas is also an option, but it is more challenging regarding injection equipment requirements and delivery, depending on location.  

Also, while gas injection can be quite effective, it must be repeatable, so it is more practical onshore from a cost standpoint. Multiple “huff-and-puff” injection steps are often required to sufficiently reduce condensate volume and depth into the reservoir. And then repeating those steps in the future is necessary, once the pressure drops back below the dew point and a bank grows rapidly again.  

So, these methods are all viable in applicable cases, but all are temporary to varying degrees and may not be practical as repeatable operations, especially offshore. There is a more recent, but uncommon, method for removing a condensate bank, which can also increase the time it takes for a bank to recur. This method, thermochemical treatment, has been field-tested with encouraging results in tight gas reservoirs, as well as in higher-permeability cases. 

Thermochemical treatment. Gas reservoirs, which experience condensate banking, are often of higher temperature, which can decrease the effectiveness of chemical treatments, such as with alcohols, acids and surfactants. A relatively new method, or at least one that would be new to have in mind for treatment condensate banking, is the injection of thermochemical fluids. Thermochemical fluids can be injected into a gas reservoir to react and generate pressure from nitrogen and heat, in-situ. An example is the reaction of ammonium chloride and sodium nitrite:^1. 

NH₄Cl + NaNO_{2 →} NaCl + 2H₂O + N₂ (gas) + ΔH (heat) 

The reaction takes place in the formation matrix and can be triggered by the formation temperature. A chemical accelerant also can be added, if necessary. The result of the in-situ reaction is generation of pressure from nitrogen gas, and heat, combining to convert condensate liquid to gas—through exceeding the dew point pressure, as well as evaporating liquid to gas. In addition, the pressure pulse from nitrogen in certain formations can create microfractures, reducing capillary forces and the resulting entrainment of condensate. In this event, more permanent removal of condensate banking may be conceivable.¹ 

Readers are encouraged to explore the literature on condensate banking, methods of mitigation, and case histories. The message is, at least, to not dismiss condensate banking as an inevitable problem that cannot be treated effectively. Treatments may not be perfect, and no single method is fully effective or permanent. It takes creativity to consider treatments combining multiple methods and technologies and to properly plan for periodic, repeated treatments to maintain optimum gas production and minimization of condensate banking, depending on the well and field conditions, logistics and economics.  

REFERENCE

1. Hassan, A., et al., “New chemical treatment for permanent removal of condensate banking from different gas reservoirs,” ACS Omega, Vol. 4/Issue 26 (Dec. 12, 2019)

Leonard Kalfayan has 44 years of oil, gas and geothermal experience. He has worked for Hess, BJ Services, Unocal, and as a consultant. He is an SPE Distinguished Lecturer and Distinguished Member. He has authored numerous publications, including 3 books, and also holds 13 U.S. patents.