US20170253977A1

US20170253977A1 - Method for enhancing the operational life of production parts in the oil and gas industry

Info

Publication number: US20170253977A1
Application number: US15/598,118
Authority: US
Inventors: Victor Champagne; Gregory Nicolas Vigilante; Christopher Patrick Mulligan; Edward John Troiano; Christopher Humiston; David C. Smith
Original assignee: New Mexico Junior College Research Foundation LLC
Current assignee: New Mexico Junior College Research Foundation LLC
Priority date: 2014-04-16
Filing date: 2017-05-17
Publication date: 2017-09-07
Also published as: US20150299863A1

Abstract

A method for improving the operational life of production parts, such as steel sucker rods, couplings, pump parts, and tubes, for use in underground recovery or production of oil and gas, includes coating the steel production parts with a layer of corrosion resistant alloy (CRA) to reduce a loss rate of the steel by improving corrosion resistance and mitigate pitting. In one embodiment, the corrosion resistant alloy is a nickel-based alloy. In other embodiments, the steel production parts can either be coated with an epoxy/phenolic layer, or coupled with a sacrificial anode. The coating process can implemented by any one of the following processes: cold spray coating; electroless corrosion resistant coating; flow forming; and electrochemical machining.

Description

CROSS-REFERENCE TO RELATED APPLICATIONS

This application for patent is a continuation of U.S. patent application Ser. No. 14/672,580, filed Mar. 30, 2015, and claims priority to U.S. Provisional Patent Application Ser. No. 61/980,174, filed on Apr. 16, 2014, and are hereby incorporated by reference in their entirety for all purposes.

GOVERNMENTAL INTEREST

The invention described herein may be manufactured and used by, or for the Government of the United States for governmental purposes without the payment of any royalties thereon.

FIELD OF THE INVENTION

The present invention relates in general to the field of subterranean extraction oil and gas. More particularly, the present invention relates to a method for improving the operational life of sucker rods, couplings, pump parts and rods or similar down hole equipment (collected referred to herein as “production parts”) for use in the oil and gas industry, through novel coatings and manufacturing processes.

BACKGROUND OF THE INVENTION

Many working oil wells depends on the sucker rods and couplings to transfer the vertical motion of the surface mounted drive system to the pump assembly located down bore in the well. The coupled string of sucker rods moves inside a tube and is connected to a pump. The combination lifts the produced fluids from the bottom of the well to the surface. Many production parts (some are fiberglass, etc.) cre solid cylindrical forged steel alloy sections with upset ends that have male threads and wrench flats, to facilitate assembly into a “rod string” made up of many sucker rods, joined with double female couplers.
The transferred vertical motion drives a “pitcher” pump assembly that forces the crude oil upward within the tubing where it is collected at the surface. Many oil wells have been suffering from the reduction in the couplings, tube and pump parts operational life, which drives the oil production costs significantly, not only in materials costs to procure new rods, but also in labor costs to replace the rods. In addition, while the rods are being replaced, the oil production is suspended, further exacerbating the costs.
Corrosion is known to be one of the major issues contributing to the degradation and failure of equipment, such as the sucker rods, in the oil industry. It is a phenomenon that develops in confined regions of a metallic material in contact with a corrosive medium. Corrosion accounts for about two-thirds of all sucker rod and coupling failures. Carbon dioxide (CO₂) generates an iron carbonate scale that tends to retard corrosion rates. However, if and when this scale is compromised, such as by cracking, abrasion, etc., then aggressive local corrosion occurs in the affected areas, and appears as deep corrosion pitting.
CO₂is soluble in water and its solubility increases as temperature decreases. For example, at 176° F. and 1 atmosphere of pressure, the normal (non-supersaturated) CO₂concentration in water is about 290 ppm. At a well temperature of about 137° F. about 58° C.), the CO₂concentration increases to about 600 ppm. The pressure impacts of a 10,000-foot deep well are also a very significant factor in solubility.
The presence of CO₂in water can result in the formation carbonic acid. The carbonic acid corrodes the steel and forms an iron carbonate (FeCO₃) reaction product. As this FeCO₃corrosion product (layer) forms, the corrosion rate tends to decrease, depending on many factors such as temperature, velocity, pH, H₂S concentration, and type of steel used. If the FeCO₃layer is not intact (e.g., not contiguous) or is cracked, localized pitting corrosion occurs.
Pitting corrosion tends to form under low flow or stagnant conditions often found in the vertical portion of an oil well tube.
The microstructure of the steel may also influence the corrosion in a CO₂environment. A pearlitic microstructure will tend to promote better adhesion of the FeCO₃layer, and thus corrosion rates may decrease. However, the presence of microstructures composed of ferrite and cementite, results in increased corrosion due to the formation of a micro-galvanic cell within the steel. Therefore, if steel production parts were used in a sweet well environment, corrosion rates are anticipated to be less for normalized steels than quench and tempered steels. This microstructural effect is evident at temperatures up to about 140° F. and has less of an effect above this temperature.
The presence of hydrogen sulfide (H₂S) can inhibit CO₂corrosion of steel due to the formation of a more protective ferrous sulfide (FeS) layer. The effect depends on the ratio of partial pressures of CO₂and H₂S, temperature, and pH.
Three prerequisites for hydrogen embrittlement are: 1) presence of hydrogen; 2) susceptible material; and 3) a tensile stress. In addition, the greatest severity for hydrogen embrittlement tends to occur at around room temperature.
In addition, microbial corrosion may occur in sucker rods. This corrosion is due to the presence of bacteria that can produce H₂S and other detrimental by-products.
Stray current corrosion may occur in the rod string if the pump jack were improperly grounded. This may lead to arcing and damage to the sucker rods.
Manufacturing defects may occur in sucker rods, couplings, pump parts and/or tubing, known as production parts, that lead to stress risers, premature damage, and failure. Examples of manufacturing defects include folds, nicks, scale, and microstructural defects, such as grain boundary melting, hardness differences (e.g., untempered martensite), and inclusions.
In addition, sucker rods are required to have a specified straightness. If the sucker rods are not straight or are bent during operation, this can lead to unevenly distributed stresses and fatigue cracking.
Numerous attempts have been made to overcome the foregoing problems; however, there still exists room for improvement. Premium production parts are made available and can be selected for operation in especially aggressive environments. These premium parts may be formed by such processes and materials as:
Monolithic Corrosion Resistant Alloys (CRAs).
Increased surface finish.
Shot peening.
Thermal spray coatings.
Furthermore, rod guides can be molded directly on the sucker rods in an attempt to mitigate wear between the rod and the tubing. However, such process is believed to have beer relatively successfully used to mitigate wear but not corrosion.
Prior to the advent of the present invention, there has been no successful, practical, and cost effective solution to overcoming the problems associated with the diminishing operational life of production parts.

SUMMARY OF THE INVENTION

The present invention addresses the foregoing concerns and presents new processes for examining high corrosion rates on sucker rods in oil and gas wells, and to develop solutions to increase the operational life of production parts
Sections of heavily corroded rods and well fluids were obtained and examined. Testing and materials analyses ruled out environmentally assisted cracking as a contributor. Moreover, analysis of the fluid and literature searches identified CO₂as a primary contributor. The following are exemplary processes that assist in the prolongation of the operational life of production parts, especially sucker rods and couplings.
A preferred process includes the use of electroless, corrosion resistant coatings technology. This process enables unique, functionally graded coatings that can be matched to the operational environment. The coatings are deposited at low processing temperatures and do not thermally alter the microstructure of substrate material. The process enables rapid deposition of conformal coatings with minimal subsequent processing needed. The coatings may be deposited with beneficial compressive residual stresses, which may enhance the operational performance of production parts, such as in sour well environments in which H₂S cracking is an issue.
Another preferred process includes the use of cold spray coating technology. The cold spray process can be performed in a production setting as well as in the field with portable systems. Additionally, cold spray depositions will form an interlocking mechanical bond to the substrate material, similar to explosive cladding. Given the specialized nature of this process, specifics on alloys, hardness, and surface conditions are often well dependent and must be assessed to enable the success of the process.
Still another preferred process includes the use of flow forming technology. The flow forming process enables near net shape manufacturing of difficult-to-machine corrosion resistant alloy (CRA) materials, such as nickel base alloys. Moreover, this process may impart beneficial compressive residual stresses to mitigate the operational performance when used in sour wells.
Yet another preferred process includes the use of the electrochemical machining technology. Electrochemical machining can be exploited for its rapid material removal rates, ability to machine complex geometries, superior surface finish, and ability to retain prior beneficial compressive residual stresses from previous processes.
An electrochemical model was developed to assess production part corrosion in the fluid environments and predicted a loss of 1.4 mm/month in depth. This model compares credibly with numerical calculations of 4.1 to 4.7 mm/month. This loss rate confirms the early failures of the production parts.
Care must be taken when selecting the appropriate corrosion resistant alloy for the desired application. Important parameters include temperature, chloride concentration, partial pressure of CO₂and H₂S, pH, and the presence or absence of sulfur.

DETAILED DESCRIPTION OF PREFERRED EMBODIMENTS

While the making and using of various embodiments of the present disclosure are discussed in detail below, it should be appreciated that the present disclosure provides many applicable inventive concepts that can be embodied in a wide variety of specific contexts. The specific embodiments discussed herein are merely illustrative of specific ways to make and use the disclosure and do not delimit the scope of the disclosure.
All publications and patent applications mentioned in the specification are indicative of the level of skill of those skilled in the art to which this disclosure pertains. All publications and patent applications are herein incorporated by reference to the same extent as if each individual publication or patent application was specifically and individually indicated to be incorporated by reference.
The present disclosure will now be described more fully hereinafter with reference to the accompanying figures and drawings, which form a part hereof, and which show, by way of illustration, specific example embodiments. Subject matter may, however, be embodied in a variety of different forms and, therefore, covered or claimed subject matter is intended to be construed as not being limited to any example embodiments set forth herein; example embodiments are provided merely to be illustrative. Likewise, a reasonably broad scope for claimed or covered subject matter is intended. Among other things, for example, subject matter may be embodied as methods, devices, components, or systems. The following detailed description is, therefore, not intended to be taken in a limiting sense.
Throughout the specification and claims, terms may have nuanced meanings suggested or implied in context beyond an explicitly stated meaning. Likewise, the phrase “in one embodiment” as used herein does not necessarily refer to the same embodiment and the phrase “in another embodiment” as used herein does not necessarily refer to a different embodiment. It is intended, for example, that claimed subject matter include combinations of example embodiments in whole or in part.
In general, terminology may be understood at least in part from usage in context. For example, terms, such as “and”, “or”, or “and/or,” as used herein may include a variety of meanings that may depend at least in part upon the context in which such terms are used. Typically, “or” if used to associate a list, such as A, B or C, is intended to mean A, B, and C, here used in the inclusive sense, as well as A, B or C, here used in the exclusive sense. In addition, the term “one or more” as used herein, depending at least in part upon context, may be used to describe any feature, structure, or characteristic in a singular sense or may be used to describe combinations of features, structures or characteristics in a plural sense. Similarly, terms, such as “a,” “an,” or “the,” again, may be understood to convey a singular usage or to convey a plural usage, depending at least in part upon context. In addition, the term “based on” may be understood as not necessarily intended to convey an exclusive set of factors and may, instead, allow for existence of additional factors not necessarily expressly described, again, depending at least in part on context.
Nickel-based alloys, and other superalloys are high performance alloys that exhibit excellent mechanical strength and resistance to creep (tendency for solids to slowly move or deform under stress) at high temperatures; good surface stability; and corrosion and oxidation resistance. These alloys typically have a matrix with an austenitic face-centered cubic crystal structure. A superalloy's base alloying element is usually nickel, cobalt, or nickel-iron. Nickel based alloy development has relied heavily on both chemical and process innovations and has been driven primarily by the aerospace and power industries. Typical applications are in the aerospace, industrial gas turbine and marine turbine industries, e.g. for turbine blades for hot sections of jet engines, and bi-metallic engine valves for use in diesel and automotive applications.
Examples of superalloys are Hastelloy, Inconel (e.g. IN100, IN600, IN713), Waspaloy, Rene alloys (e.g. Rene 41, Rene 80, Rene 95, Rene N5), Haynes alloys, Incoloy, MP98T, TMS alloys, and CMSX (e.g. CMSX-4) single crystal alloys.
There exists an empirical relationship between the alloy content of a material, and its pitting corrosion resistance. This relationship is known as the Pitting Resistance Equivalent Number (PREN), as indicated by the following equation:
PREN32 %Cr−3.3(%Mo+0.5%W)+16%N,
in which the chemical elements [Chromium—Cr, Molybdenum—Mo, Tungsten—W, and Nitrogen—N] are in weight percent. The higher the PREN, the better the pitting resistance. Alloys such as martensitic stainless steels, duplex stainless steels, and nickel-based alloys, hove been effective in providing enhanced corrosion/pitting resistance.
There are numerous instances when an adherent metal coating such as the above-mentioned alloys is desired on a substrate. Such coatings are helpful in providing corrosion resistance and conductivity as illustrative modifications to a substrate. Conventional techniques for applying such coatings include sputter coating, electrochemical deposition and explosive welding. Each of these conventional techniques has limited utility owing to attributes of each respective conventional deposition technique. A more recent technique developed to address the shortcomings associated with other conventional deposition techniques is known as cold spray impact deposition.
As used herein, the term “cold spray” (also referred to as “cold gas dynamic spraying”) refers to spraying high velocity particles (of a “feed stock powder”) using a carrier gas and a convergent-divergent type spray gun, without any combustion of the gas such as in welding or some other spraying processes. The particles impact a substrate, such as the surface of a metal part, with enough energy to deform the particles and the substrate and create a metal-to-metal bond between the particles and the substrate. In one embodiment, a production part may be coated by a CRA by positioning the surfaces of each part to form the desired coating cold spraying the substrate. After deposition of the cold spray particles, production part may be heated to further form a diffusion bond among the particles and the metal parts. Additionally, controlling the parameters of the cold spray process, the parameters of the particles, and heating the metal parts may allow control of the bond created by the cold spray application.
Conventional cold spray impact deposition uses a gas supply such as helium, air or nitrogen bifurcated to convey a portion of the gas to a heater to heat the gas stream to a temperature of between 20° and 700° Celsius. The gas stream entrains ductile material particles in a solid state and typically in a size of from 1 to 50 microns in diameter with the particles being accelerated to supersonic velocities of between 600 and 1000 meters per second through a specialized nozzle. The particles impact a target substrate, such as a production part, with sufficient kinetic energy to cause plastic deformation and consolidation with the underlying material to cause bonding to the substrate and other strata of deformed particles to build up a layer of depositing material. There are multiple improved cold spray coating apparatus and processes for applying a metallic spray coating onto a substrate with superior control of particle focus and trajectory towards the substrate. These coatings further provide very low porosity resulting from a limited number of interparticle interactions during gas mixing.
In order to examine high corrosion rates on sucker rods, couplings, pump parts and tube (hereinafter “production parts”) in oil and gas wells, and to develop solutions for increasing the operational life of the production ports, the following analysis was undertaken based on experimental and collected data. The initial focus was to apply a suite of analytical tests to the materials and the well fluids, and to examine any corrosion pitting or fractured surfaces for indication of the corrosion mechanisms.
These analytical tests include:

- I. Fluid analysis test.
- II. Materials evaluation test.
- III. Fatigue test.
  Each of these analytical tests will now be described in more details.

I. Fluid Analysis Test
A fluid analysis test was undertaken using six samples of produced oil well fluid. Each sample generally appeared stratified, with a surface oil layer over a water solution. Particulate was commonly observable in the sample jar floor. Each sample was mechanically agitated prior to sampling for further testing, in an attempt to homogenize the sample fluid.
Characterization of the well fluid was preformed to assess the sediment, presence of species specifically known to impact corrosion rates, and to determine the relative amounts. Specific attention was made to seek elements based on the literature search that would provide clear root cause of higher-than normal corrosion.
Centrifuge separation was successfully attempted, but was not particularly helpful in identifying solid particles. Measuring elemental composition, Inductively Coupled Plasma-Atomic Emission Spectroscopy (ICP-AES) was dropped because it would have been expensive and not particularly informative. It should be noted that the presence of dissolved gases could not be accurately assessed. The time between sampling and testing, along with the exposure to atmosphere would prevent any accurate determination of the presence or absence of gases. The analysis was confined to the fluid and its characteristics.
Characterization of the well oil fluids included the following:

- pH and conductivity measured via electrode probe.
- Molecular species characterization via Fourier-transformed infrared spectroscopy {FT-IR}.
- Elemental analysis of solids isolated by filtration via scanning electron microscopy/energy dispersive x-ray spectroscopy (SEM/EDS).

The analytical results and observations of the well fluid analysis are as follows:

- The well fluid pH averaged neutral with a range from 6.4 to 8.0.
- Conductivity was variable, ranging from 10.4 to 58.8 mS/cm at 20° C.
- Major water peaks and minor hydrocarbon peaks were identified in the IR absorption spectra. Organic acids were not identified during testing.

The Fourier-transformed infrared analysis (FT-IR) used to characterize the chemical elements in the fluid samples indicated that there were spikes of carbon and sulfur elements present. Since there is a limited understanding of particular corrosion behaviors in these wells, the examination of the chemistry involved and general trends was undertaken. From the fluid analysis, materials examination, and literature search, a CO₂corrosion model is a likely model.
The scope of the undertaken analysis is to assess the relative improvements that a coating or different material will yield over standard steels.
A classic iron corrosion model was used to predict the evolution of damaged profiles of carbon steel and Corrosion Resistant Alloys (CRA), such as nickel based alloys, and the changes in potential due to the changing crevice environment, thus yielding a material loss estimate. This model did not account for mass transport effects inside the crevice.
In a simulation approach, the hydrolysis of corrosion occurs when at least two electrochemical half-cell reactions take place on the steel surface. The reduction reaction occurs as follows:
O₂+2H₂O+4e⁻→4OH⁻.
The ferrous ions are produced by the dissolution of the metallic iron according to the following oxidation reaction:
Fe(s)→␣Fe₂+(aq)+2e⁻.
The general electrochemistry of the corrosion cell is the product of the above two reactions producing the iron oxide:
Fe₂ ⁺⁺2(OH)⁻␣Fe(OH)₂.
The mechanisms of corrosion are generally described as the correlation between corrosion potential and current density plotted in the polarization curve. The corrosion potential is defined as a point where both anodic and cathodic reaction occurred at the same rate, producing a net current of zero. As the potential increased, the current density increases, which also increases the corrosion rate. Beyond the highest potential point, the metal reveals a dramatic decrease in current density, forming a passive layer protecting the metal from being corroded, thus reducing the corrosion rate.
The entire corrosion process is divided into four important essentials:

- (1) An anodic region where an oxidation reaction occurs on the metal surface,
- (2) a cathodic region where a reduction reaction occurs in the electrolyte,
- (3) an ionic path for the transport of ionic species through migration of diffusion and convection, and
- (4) an electron path for the transfer of electrons between the anode and cathode.

The evolution of crevice corrosion damage in the present disclosure focuses on the first two elements of the corrosion process. Additional mass transport effects inside the crevice would potentially accelerate material loss.
The corrosion rate from numerical results will be used to predict the presence of CO₂and H₂S in the oil fluid that causes corrosion in metal. A section of 100 mm in length with a limited depth was modeled. The corrosion was initiated in the middle of the rod with a 10 mm opened crevice.
It was assumed that corrosion occurs in a very flat surface of metal, and for the purpose of this simulation. Since some thing or object had to provide the 10 mm crevice, the model included an ‘isolated object’ as the initiator. The polarization curves for metal (either carbon steel or CRA) in water and CO₂gas were identified as the local current density applied to crevice mouth. Iron was considered the key element for reaction between metal and acids in the oil fluid.
The model was estimated using a free triangular mesh applied to the geometry. The model was first solved using a stationary solver for potentials, then continued with a second step using time dependence to study the corrosion over the period of time.
The model was solved based on Nernst-Planck equation at steady-state using. The ion flux of a given species, s, is described as:
Js=−D _s
_s-z _s F _sμ_s C _s
,
where J_sis the ionic flux, D_sis the diffusivity, C_sis the concentration of ions, z is the species oxidation state, F is Faraday's constant, μ_sis the species mobility, and E is the potential. The first term on the right represents the transport of ions through diffusion. The second term describes migration, the transport of ions due to the electric field.
It was assumed that the electrolyte of the well-oil was well mixed, the spatial gradients of concentrations equals zero, the equation ion flux was simplified to:
J _s =−z _i F _iμ_i C _i
.
Using Faraday's law, the rate of metal loss due to corrosion is correlated to the molar mass of the metal, Ms; density of the metal, ρs; Faraday's constant, F; and the anodic current density at the location inside the crevice, i(E). It is described as:
[dH/dt].[1+(δH/δx)²]^{31 1/2} =[i(E).Ms]/[2F.ρ _s].
The corrosion potential is unevenly distributed from 0 to 0.034 V during the four-month duration exposure to the acid environment of the oil-well. The highest value is located at the most outer sucker rod surface, where it is exposed to the fluid. This outcome indicates that the oxygen-reduction reaction is taking place leading to corrosion.
As time progresses, the potential has increased, forming a concave shape with a larger mouth opening in the outer surface. After four months of immersing in the oil well fluid, corrosion appears to drill through the thickness of carbon steel rod. The simulation results indicate that corrosion seems to initiate in the outer surface and penetrates deeply through the sucker rod leading to corruption of the tube after being in service from one month to four months.
The analysis also estimates the corrosion penetration rate for low carbon steel rod. It took approximately four (4) months for the corrosion to penetrate the body of the small sucker rod. The penetrated corrosion value reads as 220 mils within four months or 1.40 mm/month. Comparing with the corrosion prediction, wherein the corrosion rate for Grade C carbon steel is approximately 4.1 mm/month, the simulated corrosive rate is approximately a factor of three lower.
The model was replicated by replacing carbon steel with a CRA material (e.g., nickel based alloy) for the sucker rod. The corrosion in the CRA material occurs approximately 16 times slower than in carbon steel. Even though this model is an estimation of corrosion rate, it seems to be able to perform the transport phenomena and chemical reactions for elements that cause corrosion in the well oil environments. According to experiments by Koteeswaran, M. “CO₂and H₂S corrosion in oil pipelines”. University of Stavanger, June 2010, if the corrosion rate of carbon steel were in the range of 1.20 mm/month, it is predicted that there is a significant concentration of CO₂present in the environment.
In summary, a classic iron corrosion model was utilized to assess the loss rates for the carbon steel rod and couplings, and the relative improvement that a corrosion resistant alloy would yield. This computer model predicts a loss rate of 1.4 mm of depth per month in a carbon steel sucker rod. This compares well with other experimental findings. The engineering analysis from the materials evaluation predicts a loss rate of about 4.1 to about 4.7 mm per month. Given that the model did not account for all corrosion mechanisms at work, it should be lower than the observations. This model, therefore, appears to be a credible simulation, leading to the conclusion that the use of a CRA material would slow the loss rate by approximately 16 times.
The use of a CRA material to improve corrosion resistance and mitigate pitting has a high likelihood of success. However, the appropriate material should be carefully selected based on the specific well environment in order to optimize performance and minimize cost. The use of a CRA coating or thick cladding on a steel sucker rod will have a lower unit cost than a monolithic CRA sucker rod and or coupling.
However, if not engineered properly, the interface between the coating/cladding and the substrate could be a source of eventual failure. It is anticipated that the cost of a CRA sucker rod or couplings could be several times greater than the cost of the current sucker rod material (e.g., Norris 97 steel or similar material). If this material can improve the life of production parts from one month to two years, the life cycle cost will be extremely low (e.g., cost avoidance associated with sucker rod failures).
The use of an epoxy/phenolic coating on production parts (e.g., Norris 97 or similar material) is anticipated to result in some improvements in corrosion and overall performance at a relatively low cost. However, it is unlikely that the performance of this type of coating would outperform a CRA material. Therefore, the life cycle costs associated with such an epoxy/phenolic coating would be anticipated to be greater than if a CRA material were used.
The use of a sacrificial anode is also anticipated to increase corrosion resistance. In addition, it could likely be implemented for the lowest startup cost of the three potential solutions described herein. Galvanic coupling can be strategically used in which a “sacrificial anode” (e.g., Zn) can be connected to a production part string in order mitigate corrosion. This is analogous to galvanized steel in which the zinc preferentially corrodes and thereby provides a relative corrosion protection to the steel.
However, it is not anticipated to provide the level of corrosion protection as the other two solutions (i.e., CRA & epoxy/phenolic coating). The previously discussed corrosion mechanisms can create highly localized corrosion potential, which the anode may not be able to counter unless precisely located. Because of the high costs to replace failed portions of the rod string and the lost opportunity costs associated with a non-producing well, the life cycle costs when using a sacrificial anode are anticipated to be higher than the CRA or epoxy/phenolic solutions.
II. Materials Evaluation Test
The evaluation was performed on two sucker rod pump components from two different wells that are referred to herein as B3 and D1. Qualitatively, the D1 rod was observed to be more severely corroded than the B3 rod. It was clear from the overall appearance as well as the closer view that there has been significant material loss in the D1 rod. It was also observed that the corrosion was of a general corrosion type, pitting and also some crevice corrosion, which produced the thin layers of corrosion product that subsequently flaked off. Closer examination of the B3 rod showed less attack and much less severe crevice corrosion. Pitting was present as was general corrosion.
Under closer examination, a complete penetration of the pit was observed. Also, to the right of the penetration pit, the initial formation of another pit was also observed. Between these two areas is an isthmus-like feature of darker material. We could deduce that the darker material is the oxide film formed during general corrosion, thus observing that a crevice formed underneath this layer and corrosion beneath this occurred at a later time. In addition, the top layer had no support and flaked away.
A complete assessment of the chemical and hardness of the base metal was performed. The hardness and relative alloy constituents were analyzed. After reviewing the chemical composition of the four components provided, a review of the available tube and sucker rod materials and specifications was performed.
Based on the review and assessing the hardness measured on each of the components, the material, approximate yield, and the approximate ultimate strength were deduced. The B3 rod material is an alloy steel, while all of the remaining materials are carbon steels. The tube materials were consistent with being classified as either Group 1, Grade K55 or Group 1 Grade M65 material as per API Specification 5CT. The D1 rod had composition and properties consistent with Grade C material and the B3 rod had a composition and properties consistent with Grade D special alloy steel as per API Specification 11B.
Failures of the sucker rods and couplings themselves are the primary concern and the most common form of failure in the well. In general, failure is defined as the sucker rod, couplings, pump part and tube combination failing to pump. Failure of the sucker rods and couplings, which connects the lift piston at the bottom of the well to the drive works at the surface, results from general loss of material due to corrosion and subsequent fracture of the rod.
To evaluate this failure mode, the following engineering analysis is offered. The loads applied to the sucker rod where the failures occur in the head are due to the oil column from the sucker rod pump within the tubing to the surface. Two sucker rods were analyzed, both were 0.75″ in diameter. One of these sucker rods was determined to be Grade C Carbon Steel as per API Specification 11B, and it was marked and referred to as D1 (Dyer #1).
The other sucker rod, B3 (Brown #3) had chemistry and hardness properties consistent with Grade D Special Alloy. The Dyer material is essentially is a 15XX carbon steel, the Brown material is a Ni Cr Mo steel. The tubing sizes were different for the two sucker rod pumps. The Dyer tube had about a 2.5 in. ID, and the Brown tube had about 2.1 in. ID. The wells were about 13,000 ft. deep. Assuming the density of crude oil to be 850 kg/m², the weight of oil in the Brown tube is 12,876 lbs, the weight in the Dyer tube was 21,305 lbs. This weight produced a stress of 29,147 psi in the Brown sucker rod and 48,225 psi in the Dyer sucker rod.
Since the applied loads were known, it was possible to determine the remaining area that will result in failure. The original area of the virgin sucker rod was the area of a 0.75″ diameter rod or 0.4418 in². Based on the lost thickness of was possible to determine those corrosion rates (assuming uniform corrosion) that would result in failure in the actual time (one month) or the desired life (two years) for each rod and each well. The corrosion rate was determined as a penetration rate (mpy (mili-inch per year)) or a corrosion current (mA/cm²(milliamp per square centimeter)).
III. Fatigue Analysis Test
Certain materials and configurations lend themselves to environmentally assisted cracking. These phenomena can greatly decrease service life in some steel alloys, especially when exposed to aggressive environments. To assess this potential, the fatigue and fracture mechanics properties of the materials currently used in sucker rods, couplings and the like were evaluated.
Fracture toughness is defined as the resistance of a component to resist further rapid and uncontrolled crack extension after a crack has already initiated. The set of tests to measure fracture toughness will characterize the material and will enable the determination of wherein the mechanical failure mode is brittle or ductile in nature.
A standard methodology for measuring the energy needed to propagate such a crack is defined by ASTM E1820 (Standard Test Method for Measuring Fracture Toughness). Fracture toughness coupons were extracted in the Longitudinal-Radial orientation (as defined in ASTM E399) from two separate sucker rods defined as B3 and D1, and tests were run in lab air at 72° F. In addition to the use of the results to assess environmentally assisted cracking potential, the results of the test were useful in establishing a baseline measurement for sucker rods and couplings. This baseline could be used to compare against future sucker rods and couplings should there be material, manufacturing, or environmental changes (e.g., sour wells that operate in an aggressive H₂S environment).
The fatigue test results for both B3 and D1 indicate that in both tests, the materials exhibited significant yielding and invalid toughness test results of KJIC of 269.5 and 269.4 ksi-in½. Although these test results were invalid because of very specific size requirements and other criteria established in the ASTM test standard, they did provide a glimpse into the high toughness of these materials. These tests verified that the material used in these sucker rods had a high resistance to cracking, and should fail under normal mechanical loading conditions by gross overload failure as opposed to rapid cracking events such as would happen with glass or other brittle materials (such as steels embrittled by hydrogen).
Paris Law fatigue coefficients were measured from sucker rods B3 and D1 according to ASTM E647 (Standard Test Method for Measurement of Fatigue Crack Growth Rates). The test data for both sucker rods were nearly identical and the results were averaged in order to develop the Paris Law trend line (in English units) of:
da/dN=4.399E-10*delta K ^2.89,
where da/dN is the incremental crack extension of each applied cycle, and delta K is the stress intensity range which incorporates the unique geometry and applied stresses in the component. This correlation was evaluated using computer models that approximate component cyclic life.
The model also calculated the critical stress concentration factors in bending and in tension as well as the Kf factor used in fatigue life analysis, and outputs estimate the life of the sucker rod. The findings indicate that the rod had good fatigue resistance and was unlikely to suffer early failures as a result of accelerated crack growth.
The results of the testing indicate that the material of these rods will fail in a ductile manner, absent any failure surfaces for evaluation. These materials are probably not susceptible to environmentally assisted cracking from the current wells. Thus, it is possible to rule out environmentally assisted cracking, including stress corrosion cracking, as a potential factor in the analysis.
While the present invention was described using certain exemplary, specific embodiments, those skilled in the art will recognize that the teachings presented herein are not limited to these specific embodiments. The preferred embodiments of the invention are provided for the purpose of explaining the principles of the present invention and its practical applications, thereby enabling others skilled in the art to understand the invention. Various embodiments and modifications are contemplated within the scope of the present invention.

Claims

What is claimed is:

1. A method for improving the operational life of production parts for use in underground oil recovery or production, comprising:

coating the production parts with a layer of corrosion resistant alloy to reduce a loss rate of the production part by improving corrosion resistance and mitigate pitting.

2. The method of claim 1, wherein the corrosion resistant alloy is a nickel based alloy.

3. The method of claim 2, wherein coating the production parts includes using a cold spray coating process.

4. The method of claim 2, wherein coating the production parts includes using an electroless, corrosion resistant coating process.

5. The method of claim 2, wherein coating the production parts includes using a flow forming process.

6. The method of claim 2, wherein coating the production parts includes using an electrochemical machining.

7. The method of claim 2, wherein the production parts includes any one or more of: a steel sucker rod, couplings, pump parts, and tubes.

8. The method of claim 2, wherein said production part is comprised of steel.

9. The method of claim 2, wherein said production part is comprised of aluminum.

10. A method for improving the operational life of a production part for use in underground oil recovery or production comprising:

coating the production part with a layer of epoxy/phenolic to reduce a loss rate of the production part by improving corrosion resistance and mitigate pitting.

11. A method for improving the operational life of a production part for use in underground oil recovery or production comprising:

coupling the production part(s) with a sacrificial anode to reduce a loss rate of the steel production parts by improving corrosion resistance and mitigate pitting.

12, A corrosion resistant production part comprising:

a production part; and

a layer of corrosion resistant alloy to reduce a loss rate of the steel production part by improving corrosion resistance and mitigate pitting.

13. The corrosion resistant production part of claim 12, wherein the corrosion resistant alloy is a nickel based alloy.

14. The corrosion resistant production part of claim 12, wherein the corrosion resistant alloy is stainless steel.

15. The corrosion resistant production part of claim 12, wherein the production part includes any one or more of: a steel sucker rod, couplings, pump parts, and tubes.

16. A corrosion resistant production part comprising:,

a production part; and

a corrosion resistant nickel based alloy coating.

17. The corrosion resistant production part of claim 16, wherein the production part includes any one or more of: a steel sucker rod, couplings, pump parts, and tubes.

18. The corrosion resistant production part of claim 16, wherein the production part is comprised of steel.

19. A production part assembly having a corrosion resistant coating, the production part assembly comprising:

a production part; and

a built-up corrosion resistant alloy layer adhering to the production part, the corrosion resistant alloy layer having been deposited onto the production party by first spraying a first quantity of powdered alloy particle onto a prepared production part using a jet of gas, the gas being at a temperature below the fusing temperature of the metal particles, and the jet of gas having a velocity sufficient to cause the alloy particles to merge with one another upon impact with the production part and with one another so as to form an initial continuous alloy coating adhering to the surface of the production part, and then applying successive quantities of alloy particles over the initial continuous alloy coating using the jet of gas so as to form a coating incorporating the initial continuous alloy as its base and having an overall thickness that is a predetermined thickness.

20. The production part assembly of claim 19, wherein the built-up corrosion resistant alloy comprises a nickel based alloy.