Lease Pumper's Handbook Published by the Commission on Marginally Producing Oil and Gas Wells of Oklahoma, First Edition 2003 Written by Leslie V. Langston Table of Contents Introductions A. Cover Sheet Book Title B. Publishing Information First Edition, 2003

The Lease Pumper's Handbook

Published by the Commission on Marginally Producing Oil and Gas Wells of Oklahoma, First Edition 2003 Written by Leslie V. Langston Table of Contents Introductions A. Cover Sheet Book Title B. Publishing Information First Edition, 2003


Written by Leslie V. Langston


Publishing Information. First Edition, 2003. C. Foreword. Rick Chapman, Executive Director (1996-2000) Commission on Marginally Producing Oil and Gas Wells, State of Oklahoma. D. Dedication. John A. Taylor, Chairman (1992-1998) Commission on Marginally Producing Oil And Gas Wells, State of Oklahoma. E. Author’s Introduction. Leslie V. Langston, Author, First Edition F. Commission Introduction. Liz Fajen, Executive Director, Commission on Marginally Producing Oil and Gas Wells, State of Oklahoma.


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 The Lease Pumper’s Handbook Chapter 16 Corrosion, Scale, and Cathodic Protection Section B CORROSION PROTECTION B-1. How to Prevent Corrosion Damage. To stop corrosion, the pumper must make changes in the environment that prevent the chemical reactions and electrical currents that cause corrosion. Since corrosion affects virtually all equipment on the lease, a widereaching prevention program is necessary. Good corrosion prevention begins on the first day of the first installation with the drilling of well number one and continues on all equipment at the most affordable level. This is emphasized because the cost of drilling the well, installing the necessary surface equipment, and constructing facilities must be invested while the well produces enough oil to support the recovery of this expense. As wells become marginal producers, income from production may barely cover lifting costs alone. Funds are rarely available for expensive methods of corrosion protection. There are many methods of protection, and no one system is used exclusively anywhere. The pumper should become familiar with all protective methods in order to make logical decisions. These include chemical, mechanical, and electrical methods such as: · Rust · Oxidation · Painting · Inside coating and lining · Oiling · Insulating flanges · Sacrificial anodes · Applied electrical current · Conduits · Fiberglass components · Galvanized bolted tanks · Stainless steel and metal plating · Plastic flow lines · Mechanical barriers Rust. While rust is often considered destructive, it can be a natural first level of protection for ferrous (iron-containing) metals. The rust itself can protect the outside of a flow line while the produced crude oil partially protects it on the inside. When equipment is first constructed and installed, unpainted metal rapidly oxidizes. As the rust ages, it gets heavier, a scale is formed, and the corrosion rate slows down. In the dry southwest where rainfall is low and the ground surface stays dry, surface flow lines are seldom painted or treated because rust rarely gets severe enough to cause leaks. Many unpainted lines are still in service after more than fifty years. Oxidation. Oxidation is also a natural first level of protection on non-ferrous (containing no iron) metals. Oxidation on copper, aluminum, and other non-ferrous metals provides protection similar to rust on iron. Aluminum has not been popular in oil fields except for use as temporary water 16B-2 lines to drilling rigs. When some types of oilfield acids contact aluminum, extensive damage can occur in a short period of time. Painting. Most equipment in tank batteries, especially welded tanks and lines, is painted immediately after construction to prevent corrosion. Galvanized, stainless steel, nickel-plated, and other corrosion-resistant materials do not normally require painting. However, galvanized pipe is not suitable for carrying petroleum products. Inside coating and linings. Coating lines on the inside is popular for protection against some types of corrosion, especially in downhole tubing. Linings may also be used in some lines and vessels. Another level of natural protection inside the lines and vessels comes from naturally produced compounds such as the crude oil itself and, in some instances, scale. Scale is the buildup of minerals that can be dissolved in groundwater and deposited on tubing and casing. Oiling the outside. At one time, crude and other oils were sprayed on pipe and equipment that was put in storage for extended periods of time. A good heavy oil with a small paraffin content will spray easily, protect nearly as well as paint, and last for several years. Non-corrosive oil also provides significant protection to the inside. This practice is less common today due to environmental concerns. Insulating flanges. Insulating flanges are used extensively to prevent electrical current flow. With steel lines, an insulated flange union can be placed above ground level at each end of a line, near the well, and near the tank battery. This acts as a buffer to block static and stray electricity. Sacrificial anodes. Sacrificial anodes are often installed in liquid holding vessels. For example, by installing two to four sacrificial anodes in a heater/treater near the firebox and below the water line, a path is provided for electricity to travel from the anode to the cathode, protecting the vessel. Thus, the anode provides the electrons for current flow rather than the part being protected. The anode is “sacrificed” and must be periodically replaced as it corrodes away. Electrical current. Electrical current can be imposed in selected areas to protect the outside of a downhole casing. Shallow cathodic protection wells can be drilled near operating wells and, by use of a sacrificial anode in these holes, small amounts of current (milliampere range) can be directed to the wells and removed at the wellhead to greatly reduce casing material loss and prevent casing leaks. Figure 1. A cathodic protection well. Conduits. Conduits are used extensively where lines must pass under roads to protect them from moisture. Vents are also installed to allow leaking fluids to escape. 16B-3 Fiberglass. Initially, fiberglass was used inside tanks to extend their life. Now tanks made entirely of fiberglass are available. These are widely accepted in water disposal and chemical injection systems, and their use continues to expand for holding crude oil. Galvanized bolted tanks. Galvanized bolted tanks are not subject to corrosion and were standard for years. Many are still common in the field. Stainless steel and metal plating. Stainless steel bolts, seal rings, gaskets, and small tubing have replaced more corrosive parts that fail due to embrittlement and metal fatigue. Nickel plating is also highly used. Plastic flow lines. In recent years, plastics such as polyethylene, polyvinyl chloride (PVC), and other synthetics are replacing steel and rubber in corrosive situations. Chemical protection. Chemicals still offer protection in casings and other hard-to-reach areas. These chemicals are constantly being improved and are very effective. Mechanical barriers. Mechanical methods can effectively stop some equipment corrosion problems. One method is to remove oil- or water-saturated soil from contacting lines or equipment. Also, insulating materials such as gravel and tarred felt under tanks will allow air to circulate and greatly extend their lives. Tarring and wrapping underground black metal lines prevents water and chemicals in the soil from contacting the lines. This method is often used to protect pipe in wet areas. Finally, a simple downhole pump ball and seat can stop oxygen from entering open annulus valves, yet allow gas to escape. B-2. Locating Corrosion Damage Downhole. Corrosion downhole at the well has caused production problems since the first wells were drilled. Corrosion can create holes in the casing and cause formation leaks in upper zones. This can also allow oil to flow out the surface pipe valve and overflow the cellar. The hole in the casing can even be in an offset well rather than one from which hydrocarbons are escaping. The surface valve cannot be closed in this situation because it may force the oil and gas to break into the upper freshwater zone, compounding the problem. Temperature surveys are conducted periodically on flowing wells to check for holes in the casing. The expansion of the escaping fluids at the leak creates a cold spot that can be detected by the survey. Another method of locating holes in casing is to run a casing survey. Gas pressure can be injected into the annular space with the well shut in, depressing the liquids back down to the casing perforations where the pressure chart will level off to a straight line. As the gas injection is stopped and the well sits pressurized for a 24-hour period, the pressure should remain constant on the chart. If it falls, there is a hole in the casing. B-3. Protecting the Casing Long String. Protecting the inside of the casing string that is cemented through or to the oil producing zone can be important in corrosive wells. Protection can be achieved by periodically scheduling the application of a chemical protective inhibitor blanket on the surface of the pipe all the way down the hole by batch injecting the chemical into the annular space. A carrying agent, such as several barrels of crude oil or water, may 16B-4 need to be mixed with the chemical to give it sufficient volume to allow the inhibitor to quickly flow by gravity to the bottom of the well without channeling or streaking on the way down. This results in 100% coverage. Preventing electrochemical corrosion of the outside of the casing requires a different approach. Since the string of pipe is cemented as it passes through the impervious cap and is bolted at the wellhead, the only opening into it is the surface valve on the wellhead. Drilling mud is usually caked around the outside of the casing from the surface down, so corrosioninhibiting liquids cannot be injected at the surface and be expected to coat the outside of the pipe. The solution is to block or stop the electrochemical process, which is caused by oxygen and acid. The use of insulating flange unions. Insulated flange unions (Figure 2) are installed at the well and the tank battery to prevent the flow of electrical current into the well through the casing. When electricity flows into the casing, metal is removed at the point where it leaves the well. These points act as anodes. By preventing the flow of electricity into the well, the amount of iron lost will be reduced. Figure 2. An insulated flange union that is installed near the well. The valve is used to periodically record line pressure. The use of sacrificial anodes. The ideal solution is to drill another shallow hole nearby and install a series of sacrificial anodes. Lines are run to the surface and connected through a control panel to a power line. A controlled electrical current is run through the sacrificial anode from this special well. The current runs through the earth and enters the well casing and comes up through the casing. This turns the casing anode into a cathode and corrosion stops. A protective scale will even develop on the outside of the casing at this point, offering additional protection. B-4. Corrosion Protection at the Tank Battery. Corrosion protection at the tank battery begins before the tank battery is constructed. As the tank battery is constructed, appropriate steps of the construction are directed toward corrosion protection. Tank battery elevation and ground protection. The tank battery location is elevated several inches above the surrounding area. Dirt is bladed up to give it a slight elevation above the surrounding terrain. A side taper is added that will allow rainwater to run off. Several cubic yards of crushed rock are placed under the vessels so air can circulate under them to evaporate any water that might be present. This rock is then covered with a double layer of 120- pound roofing felt to further insulate the tank from the rock. The pressurized vessels are set on concrete bases to keep them level and support the weight of the vessel, fluid, and lines. Crushed rock may then be spread over the open ground to control vegetation growth, which may trap moisture and promote corrosion from organisms. 16B-5 Lines protection. When lines are laid, areas with heavy vegetation and standing water should be avoided. Coated and wrapped pipe or elevated lines offer some protection when these areas cannot be avoided. Many styles of insulated unions are available for use near the well and also just before the flow lines enter the tank battery to reduce electrochemical corrosion in the line. Protecting vessels on the inside. Paint is always used at the tank battery as the first method of protecting vessels. A second method is to protect the inside of the vessel with special epoxy-type paint and fiberglass liners. The method selected to protect the vessel on the inside will depend upon what corrosive agents are contained in the produced crude oil. Fiberglass vessels and PVC water lines have also reduced some corrosion problems. Improved fiberglass vessels (Figure 3) are becoming more common as new batteries are built and vessels replaced. Low-pressure water injection systems are being constructed with plastic and PVC. Figure 3. Fiberglass gun barrel or wash tank with PVC water leg to reduce problems from line corrosion. Another method is to protect the vessel with chemicals. These may be injected at the tank battery, but the most logical place to inject them is down the casing annulus to protect the full system. Sacrificial anodes are widely used in heater/treaters (Figure 4). These anodes must be replaced as they corrode in order to provide continual protection of the vessel. The anode is inserted into the vessel in the lower water area, and a ground wire is attached from the anode to the firebox flange. Here, current is diverted into the line system to protect the bottom section of the heater/treater from pitting. Oil-saturated dirt is removed from around the steel lines and clean sand put back into its place. This stops the formation of galvanic cells which cause line leaks. Figure 4. Heater/treater firebox view with two sacrificial anodes visible, one to the right and the second directly below the fire tube flange. 16B-6