Patent Application
20200011472
The present invention relates in general to tubes and pipes, especially tubing for use in oil wells and other wells, and to methods for making these tubes and pipes.
Tubes and pipes are used to transport oil or natural gas from the hydrocarbon reservoir to the earth surface. Tubes and pipes are usually hollow and cylindrical in shape. Oil is generally removed from the ground using a pump-jack. This equipment is mounted on the surface of the earth above an oil reservoir. The pump-jack is connected to a down-hole pump located at the bottom of an oil well by a string of interconnected sucker rods, which extends inside a string of tubes. In some technical literature, this string of tubes is referred to as production tubing. Through the action of the pump-jack, oil is pumped from the reservoir to the surface for collection.
Corrosion in the oilfield can be caused by many sources: hydrogen sulfide (H2S), carbon dioxide (CO2), dissolved oxygen, brinish disposal water, highly acidic soil conditions and many others. Crude oil and natural gas can carry various high-impurity products which are inherently corrosive. Continual extraction of CO2, H2S, and water through oil and gas components can over time make the internal surfaces of these components to suffer from corrosion effects. Corrosion reduces productivity, and causes downtime for maintenance, or worse, replacement. Each year, corrosion costs oil and gas operating companies billions of dollars in lost revenue and reduced operating profit.
Several conventional methods are currently available for reducing corrosion of the internal surfaces of tubes and pipes used in the oil and natural gas industry.
One method is to provide a lining to the internal core of the tubes and pipes. In some instances, the lining for these tubes and pipes is made of a non-metal material such as polythene (PE) or high density polyethylene (HDPE). A disadvantage with this type of lining is the lining's poor temperature resistance. The maximum temperature cannot exceed 80° C. This type of lining is not suitable for deep thermal recovery wells. Also, this type of lining is not suitable for heavy oil or bitumen recovery, because heavy oil or bitumen is very dense and requires steam (sometimes having a temperature of up to 300° C.) to get the bitumen up from underground. Additionally, the temperature for washing this type of lining cannot be very high either. Therefore, the application of this type of lining is rather limited. In some instances, the internal lining consists of stainless steel or ceramic materials. Because the lining material and the base material of the oilfield tubing may have different thermal elongation rates, this also causes a problem in its use. Additionally, this type of lining has an inner lining thickness of 3 mm-5 mm, so that the inner diameter of the oilfield production tubing becomes smaller by 6mm-10mm, thereby affecting the performance of the oilfield production tubing.
Another method is to coat the internal surfaces of the tubes and pipes with epoxy powder coating to achieve some level of anti-corrosion effect. Since the bonding between the epoxy coating material and the substrate of the tubes and pipes is a mechanical bonding, the bonding strength is only in the range of 20 MPa to 70 MPa. This type of epoxy coating has poor resistance to abrasion and high temperature.
Another method is plating, for example, electroplating. Although plating may provide good temperature resistance, the layer created by plating could easily peel off in some complex oil well conditions. Additionally, the plating process can cause serious environmental problems. The plating process is not environmentally friendly.
Therefore, it is desirable to provide methods for making tubes and pipes which are resistant to corrosion in environments like those found in oil wells. It is also desirable to provide tubes and pipes which are resistant to corrosion for use in the oil and natural gas industry.
In drawings which show non-limiting embodiments of the invention:
Throughout the following description, specific details are set forth in order to provide a more thorough understanding of the invention. However, the invention may be practiced without these particulars. In other instances, well known elements have not been shown or described in detail to avoid unnecessarily obscuring the invention. Accordingly, the specification and drawings are to be regarded in an illustrative, rather than a restrictive, sense.
One aspect of the invention relates to tubes and pipes which are resistant to corrosion and methods of making these tubes and pipes. This aspect of the invention is applicable to oilfield tubing, casing, and oil pump barrels. This aspect of the invention is also applicable to oil and natural gas transport pipes.
One aspect of the invention relates to methods of coating the internal surfaces of tubes and pipes. The oilfield tubes are usually hollow and cylindrical in shape. Each tube has a longitudinal axis, an inner wall with an annular surface, and a predetermined inner diameter. The dimensions of oilfield tubes are usually regulated by API (American Petroleum Institute) standards. The length of such oilfield tubes can be 9 meters (9000 mm) or more, whereas the internal diameter (ID) is in the range of 40-90 mm. Therefore, the length/ID ratio of these oilfield tubes is 100:1 or more. In some embodiments, the oilfield tube is formed of low carbon alloy steel materials.
One aspect of the invention relates to methods of forming an anti-corrosion layer on an inner or outer surface of a tube. An example method comprises preheating metal or alloy powder at a first temperature range (e.g., 200° C.-450° C.) and depositing the preheated metal or alloy powder on a surface of the oilfield tube to form a coating layer. The method also comprises heating the deposited metal or alloy powder coating layer on the surface of the oilfield tube to a second temperature range (e.g., 760° C.-1300° C.) which is higher than the first temperature range to melt the powder, such that slag float to the top of the coating layer and the resulting silicides and borides are dispersed in the coating layer. The particles of the metal or alloy powder and the substrate (i.e., the oilfield tube) are bonded. The final coating layer is a dense crystalline structure comprising a metallurgical bonding layer bonded with the tube substrate. The bonding strength of the coating layer is about 200 MPa or higher. The coating layer formed using this method has resistance to impact, resistance to wear, resistance to corrosion, and has a mirror-like appearance. When used in the oilfield, the coating layer protects the underlying tube substrate from corrosion, and unlike epoxy coating, the metal or alloy coating layer generated this way does not peel off easily.
Another example method of forming an anti-corrosion layer on an inner surface of a tube involves centrifugal welding (also known as centrifugal casting). The method comprises preheating the tube to be coated to a temperature range which is high enough to melt the metal or alloy powder for coating the tube (for example a temperature range of 900° C.-1300° C.), and while rotating the tube, pouring the molten metal or alloy powder into the tube such that the molten metal or alloy powder is spun by a centrifugal force and deposited evenly on the internal surface of the tube, and then forming a coating layer by cooling down the tube. The bonding strength of the coating layer formed using this centrifugal welding method is also about 200 MPa or higher.
The alloy coating may comprise a superalloy material characterized by high resistance to wear and corrosion. Superalloy is an alloy that usually comprises one or more of Fe, Ni, Co, and Cr. In some embodiments, the alloy coating comprises a Ni-based alloy. In some embodiments, the alloy coating comprises a Co-based alloy. In some embodiments, the alloy coating comprises a Fe-based alloy. In some example embodiments, the percentage of Ni by weight in the Ni-based alloy may be more than 50%, or more than 60%, or more than 70%. In some example embodiments, the percentage of Cr by weight in the Ni-based alloy may be in the range of 5% to 20%, or 10% to 15%. In some example embodiments, the Ni-based alloy for alloy coating may comprise in percentage by weight 70-80% Ni, 10-15% Cr, 0-8% Fe, 0.2-0.4% C, 3.0-4.5% B, 0-0.02% P, 0-0.02% S.
The tube section 1 is characterized by comprising internal anti-corrosion alloy layer 3, external anti-corrosion alloy layer 4, and end anti-corrosion alloy layer 5. The tube section 1 has two end portions and each end portion comprises threads. The threads allow tube section 1 to be threaded connected to tubing connector, as is shown in
The tube section as described in this specification is advantageous because conventional tube sections do not have this combination of anti-corrosion alloy layers, especially the combination of external anti-corrosion alloy layer and end anti-corrosion alloy layer and internal anti-corrosion alloy layer which are contiguous. This solves the problem that conventional tube sections are not resistant to corrosion at their external surface (especially the threads) and at their terminal end.
In the
In some embodiments, the anti-corrosion layers are metallurgically bonded to the substrate of the tube section with bonding strength of more than 200 MPa. In some embodiments, the anti-corrosion layers are heat-resistant. This is also advantageous. As mentioned earlier, bitumen recovery may require steam (sometimes at a temperature of up to 300° C.) to get the bitumen up from underground. There are two type of heat resistance: physical heat resistance and chemical heat resistance. In some embodiments the anti-corrosion layers comprise a material that exhibits both physical heat resistance and chemical heat resistance when exposed to a temperature of up to 100° C., 200° C., 300° C., or 350° C.
In this assembly, the anti-corrosion layers (e.g., anti-corrosion layer 4) of tube section 1 overlap with the anti-corrosion layer 6 of tubing connector 2. This overlapping arrangement creates a seal or barrier to corrosive medium and can prevent corrosive medium flowing inside the tube section from leaking or penetrating into the back of the threads of the tube section and causes corrosion to the threads.
As will be apparent to those skilled in the art in the light of the foregoing disclosure, many alterations and modifications are possible in the practice of this invention. The scope of the claims should not be limited by the preferred embodiments set forth in the examples, but should be given the broadest interpretation consistent with the description as a whole.
