Flowing Wells
(Eq 7)
Corrosion problems in flowing wells are somewhat different from those encountered in artificial lift wells in that velocity becomes an important factor, and higher pressures lead to higher CO2 partial pressures. Treating methods are more limited because of completion requirements.
Gas condensate wells may produce gas, hydrocarbons, formation water, acid gases (CO2 and H2S), and organic acids. If the producing conditions allow liquid water to be produced or to condense on the tubing, corrosion is likely.
In wells producing formation water, corrosion may occur anywhere in the tubing string, wellhead, and flow line. Temperatures in the well bore will affect the corrosion rate, and flow velocities also affect metal loss. The salinity of the water and acid gas content are factors in corrosion rates.
Wells that produce no formation water will corrode where the dew or condensation point of water is reached and free water condenses on the tubing. The water will dissolve CO2 or H2S and become corrosive.
Carbon dioxide corrosion is particularly damaging in condensed water. Dissolved CO2 can lower the pH of water to less than 4.5 at CO2 partial pressures of 69 kPa (10 psi) and tempera-tires of 75 oC (170 oF). Carbon dioxide corrosion can cause severe pitting when conditions of temperature and salinity form iron carbonate scale in a noncontinuous or spotty layer. Organic acids increase CO2 corrosion rates by dissolving iron carbonate scale and by lowering bicarbonate content so that further iron carbonate scaling is prevented.
H2S also dissolves in water, although the pH reduction is not as great as that found with CO2. Metal loss and pitting, along with hydrogen embrittlement and sulfide-stress cracking, may be present.
Oxygen is not present in the production stream, and it is not a problem unless it is introduced into the system by corrosion treatments. It then can have some effect on corrosion and will cause pitting of ferritic stainless steels.
Materials Selection. Most gas wells are completed with low-alloy steels for economic reasons. These steels will perform satisfactorily in most wells, and the application of coatings and the use of corrosion inhibitors permit their use in severe environments of high temperature, pressure, and CO2 content.
Many Tuscaloosa Trend wells completed with carbon steel tubing are producing with no corrosion failures - when coated and inhibited. Producing conditions range to 230 oC (450 oF) bottom hole temperature, 124 to 138 MPa (18 to 20 ksi) pressure, and CO2 content of 5% or more. Hydrogen sulfide is also found in some wells at concentrations of 20 to 50 ppm.
Alloy Tubulars. Where conditions and economics warrant, corrosion-resistant alloys can be used. Steel with 9% Cr and 1% Mo has low corrosion rates up to 100 oC (212 oF). Higher corrosion rates and pitting become a problem at higher temperatures. The partial pressure ofCO2 is not a factor at temperatures below 240 oC (465 oF). Steel with 13% Cr is effective up to 150 oC (300 oF). Oxygen will cause severe pitting of 13% Cr steel; therefore, chemical injection systems must be kept oxygen free by an inert gas blanket on storage tanks.
If H2S is present, 9% Cr and 13% Cr steels can be used at hardnesses below 22 HIRC. Of the two, 13% Cr steel is more resistant to chloride cracking.
Coatings. Low-alloy steels can be coated for corrosion resistance. Coatings include baked-on phenolics, epoxies, and polyurethanes with fillers to give the required thickness, coating integrity, and corrosion resistance. Proper application is required for an intact coating that conforms to requirements. Tubing surface preparation, application methods, coating thickness, and holiday detection are part of the inspection and quality assurance process.
Joints and connections should be designed so that the continuity of the coating is unbroken. The first few threads inside the female connection and the pin nose must be coated. A compression ring can be installed to ensure joint integrity.
Special care must be taken when the wireline operations are carried out in the coated tubing. Coatings are easily damaged or scratched, and once the coating is broken, corrosion and disbonding of the remaining coating can take place.
Wireline guides and running speeds of less than 0.5 m/s (100 ft/mm) will minimize-damage. A corrosion inhibitor should be used directly after wireline operations. The wireline tools should not have sharp edges and should be plastic coated. Wireline centralizers should also be used.
Coatings are also subject to disbondment if pressures are released suddenly. Gases can penetrate the coating, and when a sudden pressure drop occurs, the gases will expand and lift the coating.
Inhibitors. Corrosion inhibitors are an effective means of corrosion control, and they are required in highly corrosive environments in which carbon steel is used. They are needed even if the tubing is coated, because a holiday-free coating does not exist. Combination coating-inhibitor procedures are particularly effective.
The most commonly used inhibitors function by forming a film on metal surfaces that stops the flow of corrosion current. Nearly all inhibitors are fatty amines or quaternary ammonium compounds. The nitrogen in the molecule possesses a strong cationic charge and is chemically absorbed onto anodic sites on the metal surface. Cross-bonding of the film and the attraction of a layer of oil aid in isolating the surface.
Inhibitors are selected for several characteristics. The major consideration is the lowest corrosion and pitting rate, followed by film persistence, nondamaging to producing formations when squeezed, and minimal system upsets due to emulsion stabilization.
Once an inhibitor is selected, a treating method is used that fulfills the system requirements. Several methods are commonly used to treat flowing wells; batch treating, continuous injection, and squeezing will be discussed below.
Batch treating involves the intermittent addition of relatively large quantities of inhibitor solution to the annulus or down the tubing of a gas condensate well. A batch treatment in a flowing well consists of dumping a solution of inhibitor in condensate or diesel fuel down the tubing, shutting the well down to allow the inhibitor solution to fall to the bottom, and repeating at a set interval. The disadvantage of this treatment is that the inhibitor may not go to bottom.
The tubing may contain up to 50% of its volume of water and oil, and the bottom of the well below the static shut-in fluid level may not be treated.
A method of treatment that ensures that the batch will reach the bottom of the well is tubing displacement. A batch of inhibitor in oil, usually one-third of the tubing volume, is pumped in, and enough condensate or oil is pumped in to displace the batch to bottom. The well is shut in for a few hours and brought back on production. This ensures that the tubing is treated all the way to bottom. Tubing displacements may last from a few days to a month or so, depending on the severity of the corrosion problem, the produced fluids, the flow velocity, and the ability of the inhibitor to form a persistent film.
Nitrogen or another gas can be used to displace the inhibitor solution instead of liquid. This is of value if the well has a low bottom pressure, because filling the tubing may permanently stop production or “kill” the well. It is also of value where volumes of oil cannot be easily moved around. A variation of the nitrogen batch is to atomize the inhibitor solution into the nitrogen as it is pumped into the well. The inhibitor selected should have good film persistency.
Continuous injection consists of constant addition of small concentrations of inhibitor into a producing well. The chemical can be added into a chemical or capillary string or down the annulus of a packerless completion. Chemical injection valves in a side pocket mandrel can be installed so that the solution can be pumped continuously into the annulus of a well with a packer.
In the Tuscaloosa Trend, wells were originally completed with a Y-block and kill string. This string was used for chemical injection. Wells were then completed with a packer and a chemical string, and later with a packerless completion where the inhibitor was added down the annulus.
In deep, hot wells, the inhibitor is added diluted in condensate. This is necessary because the gas is undersaturated with hydrocarbon. At high pressures, gas acts as a liquid and may strip the solvent from the inhibitor. The amount of condensate is calculated to saturate the gas. Some wells have been treated with a water solution or dispersion of inhibitor instead of condensate.
Capillary strings are small-diameter, armored tubing that is strapped to the outside of the tubing as it is run into the well. A surface tank, pump, and filter are installed. The filter is necessary to prevent particles from plugging the small-diameter tubing. Inhibitors must be selected that do not polymerize, because this would also plug the capillary.
A recent method of treating a well with a packer consists of using a perforating gun to shoot holes in the tubing. The inhibitor is pumped down the annulus and through the holes. This method is said to be more economical than recompleting the well.
Continuous treating of deep, hot wells requires an inhibitor that will not break down or form a gunk or char. This is particularly important in wells treated with a capillary string or down the annulus where the inhibitor solution must remain for an extended period of time. A surface filtering system is also required for capillary string treating.
The deep, hot wells in the Tuscaloosa Trend require an inhibitor that will withstand tempera-tires to 230 oC (450 oF) without breaking down. Although the chemical strings in the wells that have not been converted to packerless completions are large in diameter (25 to 50mm, or 1 to 2 in.), plugging problems may occur. Most of this is due to salt plugs, and the condensate has a natural fouling tendency. Therefore, any tendency to form an insoluble residue by the inhibitor adds to the problem.
A high-pressure high-temperature stability test is run in lease fluids to ensure the stability of the inhibitor. The amount of inhibitor required will range from 10 to 100 ppm under most conditions. Extremely corrosive wells may require more.
Squeezing involves placing an inhibitor solution into the producing formation far enough back from the wellbore so that a continuous feedback of inhibitor is obtained. The squeeze is sized so that a predetermined life is obtained. Field crude, condensate or diesel oil are commonly used as diluents for squeeze treatment.
The inhibitor must have the proper solubility in the diluent, and it must not form a gunk or severe emulsion with produced water. Either condition could cause temporary or permanent loss of permeability and subsequent loss of production. A core test is sometimes conducted to select an inhibitor for a tight, or fairly low permeability, formation. Film persistence is no as important as continuous protection, because inhibitor will be present in the production stream at all times.
In some reservoirs, condensate is above critical temperature and therefore exists as a gas. This condition is known as a retrograde reservoir, because when the pressure is lowered, condensate comes out of solution with the gas, rather than the normal condition in which lowering the pressure vaporizes the condensate.
A dry reservoir that contains no liquid condensate should not be squeezed. Permanent loss of relative permeability will occur, and gas production rates and hydrocarbon recovery will be decreased.
One common objection to squeezing is that inhibitors are cationic and will oil-wet the formation. The wetting characteristics of a surface-active material are based more on its hydrophile-lipophile balance (HLB), which is a measure of the tendency of the inhibitor to water-wet or oil-wet a surface, than on reservoir properties.
The HLB is determined by the size and type of oil- or water-soluble parts of the molecule.
Nonionic surfactants are used to oil-wet materials in cleaners. Sulfonates are excellent water wetters, while other sulfonates are used as oil wetters. Cationics follow the same rules. In fact, polyamines and quaternary ammonium compounds are used in workover fluids to water-wet silicates.
It is most likely that some oil wetting of the formation occurs (the inhibitor goes into the oil in the reservoir). This is what causes a squeeze to work. Nevertheless, any change in the wettability of the formation is reversible. The formation immediately begins to return to its original state once the wetting agent is removed or begins to dissipate. Natural or simulated core tests can be conducted to ensure that no formation damage will occur from the inhibitor.
The loss of production that can result from a squeeze is due to the formation of a stable emulsion in the area immediately adjacent to the well-bore. This emulsion is nearly always a water-in-oil emulsion, which is very viscous. The high-viscosity emulsion will not flow through the pore throats. Emulsion blocking can be prevented by proper inhibitor selection and by adding demulsifiers to the squeeze.
A typical squeeze can be performed in the following manner. First the amount of inhibitor required for the projected life of the squeeze should be calculated:
(Eq 7)where V is the volume of inhibitor (gallons), P is the total daily production in barrels (including both oil and water), D is the expected squeeze life, and ppm is the amount of inhibitor feedback desired (this is multiplied by 3, because it is assumed that only one-third of the inhibitor will remain in place that will desorb and feedback). The remaining five steps are as follows:
• Dilute the inhibitor with crude, condensate, or diesel oil to 10%.
• Pump a spearhead of 5 to 10 barrels of oil with 19 L (5 gal) of demulsifier
• Pump the main body of the squeeze treatment into the formation
• Overflush with one tubing volume plus one day’s production volume of oil (19 to 38 L, or 5 to 10 gal, of demulsifier can be added to the overflush)
• Shut in the well for 12 to 24 h
This procedure can be modified to suit the requirements of a particular situation.
In many applications, the amount of over-flush needed to place the inhibitor properly is too large, or filling the tubing may kill a low-pressure flowing well. The use of nitrogen instead of hydrocarbons overcomes these restrictions.
In a nitrogen squeeze, the inhibitor solution is displaced downhole and into the formation with an equivalent amount of nitrogen.
This leaves the tubing empty and charges the formation so that it flows back readily.
This procedure can be modified so that the inhibitor solution is atomized into the nitrogen as it is injected. Both of these procedures have been used with excellent results. The wells could be returned to production in 4 h, and due to the charging effect, the increased production rates for a day or so compensated for the production loss during the squeeze.
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