Downhole Corrosion Research Articles

Overview of Economic and Engineering Aspects of Corrosion in oil and Gas Production

Distinguished Author Series articles are general, descriptive representations that summarize the state of the art in an area of technology by describing recent developments for readers who are not specialists in the topics discussed. Written by individuals recognized as experts in the area, these articles provide key references to more definitive work and present specific details only to illustrate the technology. Purpose: to informthe general readership of recent advances in various areas of petroleum engineering. Introduction Corrosion in oil and gas production has important economic aspects. The direct losses resulting from corrosion--i.e., the cost of replacing corroded parts--are often minor compared with indirect costs parts--are often minor compared with indirect costs such as the loss of revenue caused by lost ordeferred production. An exception is the case of offshore production. Anexception is the case of offshore production, where the direct loss resulting from production, where the direct loss resulting from corrosion of an offshore platform can be extremely expensive. Many phases of oil and gas production are affected by corrosion. Two corrodents are responsible for problems found in the petroleum industry: dissolved problems found in the petroleum industry: dissolved oxygen and acidicspecies, most commonly CO2. Dissolved oxygen accounts for the corrosive nature of seawater and produced water and also for the corrosive nature of soil. CO2accounts for corrosion in many oil and gas wells. H2S, when present, rendersproblems with dissolved oxygen and CO2 even more serious. H2S also can introduce a serious cracking problem, sulfide stress cracking (SSC), when it contacts high- strength steel that is under stress. The combined action of acorrodent with cyclic (periodic) stress can result in corrosion fatigue, a problem often found in drillpipe and in the sucker rods of pumped wells. Besides serious downhole corrosion problems associated with oil and gas production, corrosion problems also occur frequently during waterflood problems also occur frequently during waterflood operations in which produced water or seawater is injected. In each case corrosion-preventive measures are available(such as oxygen removal or corrosion- inhibitor injection), but they require careful application. Corrosion resulting from corrosive soil is potentially serious for pipelines, tank bottoms, and well casings. An electrical method of corrosion control, cathodic protection, is often applicable to these cases. Offshore protection, is often applicable to these cases. Offshore platforms and related pipelines present severe potential platforms and related pipelines present severe potential corrosion problems that are controlled by coatings and by cathodic protection. Corrosion is an economic as well as an engineering problem. The cost of corrosion to the worldwide problem. The cost of corrosion to the worldwide industry is staggering. For example, in a 1975 study, the annual cost of corrosion in the U.S. alone was estimated at $70 billion. Of this total, about15% or $10 billion was considered avoidable--i.e., could be saved through existing corrosion-control technology. The cost of corrosion in the petroleum industry no doubt represents a large fraction of the total cost. Besides the economic importance of corrosion, two other aspects make corrosion control an urgent consideration: conservation and human safety. Corrosion represents a waste of valuable resources and requires care to ensure public safety and welfare. This paper examines both the economic and engineering paper examines both the economic and engineering aspects of corrosion and its control. Economic Impact of Corrosion Two types of losses are attributed to corrosion: direct and indirect. Direct losses are those that can be accounted for directly, such as replacement costs, including parts and labor, and protection costs such as the cost of alloying, corrosion inhibitors, coatings, cathodic protection, and R and D. Indirect losses caused by corrosion failure can be far larger than directlosses. JPT P. 1033

North Sea Downhole Corrosion: Identifying the Problem; Implementing the Solutions

Summary Tubing failures caused by CO2 corrosion and erosion are examined. Corrosion inhibitors were used for batch treatments, formation squeezing and continuous injection downhole through the annulus. Plastic-coated tubing also was used. Evaluation was by surface corrosion monitoring, tubing caliper surveys and inspection of recovered tubing. Economics were reviewed. Introduction The Ekofisk field was discovered in the Norwegian sector of the North Sea in late 1969 by the Phillips Norway Group. This group is composed of Phillips Petroleum Co. Norway (37%), Norske Fina A/S (30%), Norske Agip A/S (13%), and the Petronord Group (20%). Seven geologically separate Fields have been developed with eleven producing platforms. Phase 1 of development was the completion of four subsea wells tied into a converted jackup with tanker loading using single-point mooring buoys. Phase 2 was the installation of three production platforms, subsea pipelines, and a million-bbl (159 000-m3) concrete storage tank. Phase 3 was in two parts. First, three production platforms, an oil line to Teesside, England, and a gas line to Emden, Germany, were installed. Finally, five more production platforms were brought on stream in 1979, resulting in platforms were brought on stream in 1979, resulting in the seven-field Greater Ekofisk development. There are 120 wells completed with most using 4 1/2-in. OD, 12.6-lbm/ft (114-mm OD, 18.8-kg/m) N-80 (after 1979, L-80 was used) tubing inside 7-in., 29-lbm/ft (178-mm. 43.2-kg/m) N-80 casing. Most wells are deviated, with a maximum deviation of 55 degrees. In a few of the higher-volume wells, a 5 1/2- × 5- × 4 1/2-in. (140- × 127- × 114-mm) tapered tubine string was selected. Except for the 5 1/2-in. (140-mm)completions, a 3.81-in. (96.8-mm) seating nipple was set at 550 ft (168 m) to locate wireline retrievable safety valves. The larger completions have 4.56-in. (115.8-mm) seating nipples. The production rates varied considerably both within and between fields. The low water-cut production was coupled with a CO2 content of 1.5 to 3 mol% in the gas phase (Table 1). phase (Table 1). Corrosion was found first in the surface flow lines and downhole safety valves in 1976. The first tubing failures occurred in 1978. A corrosion task force including personnel from. operations, corrosion, reservoir, process, personnel from. operations, corrosion, reservoir, process, and drilling engineering was established to recommend and to coordinate projects for combating the downhole corrosion. Three tubing failure case histories are reviewed in the First section of the paper, then control methods used and the results are described. Case History 1 Table 1 summarizes the flowing conditions for Well 1. This 10.500-ft (3200-m) total depth (TD) oil well was in service for only 309 days with 68 days downtime before the tubing was perforated because of erosion/corrosion. The tubing pared at a depth of 1,400 ft (427 m) during the work over to replace it. Parting was caused by severe circumferential wall thinning. The well was deviated 7 degrees at this point. The flowing velocity ranged from 21 to 61 ft/sec (6.4 to 7.9 m/s) from the bottom to the top of the tubing. Fig. 1 shows a perforated tubing length from a depth of 5,700 ft (1740 m). The corrosion attack is concentrated in one quadrant of the tubing. The deviation at this depth was 35 degrees. The CO2 partial pressure was 90 psi (620 kPa), and the well tests had shown negligible free water at the separator. Subsequent testing indicated water production as a tight emulsion of approximately 1%. The estimated corrosion rate for the failure is more than 400 mil/yr (10.2 mm/a). JPT P. 239

Weighted Inhibitors Solve Special Oil-Well Corrosion Problems

Abstract The weighted liquid corrosion inhibitors provide an effective and economical means of mitigating corrosion in wells that heretofore were difficult, or impossible, to effectively treat with conventional corrosion inhibitors. The high-density liquid corrosion inhibitors have been very effective in treating the following types of wells: High-fluid-level pumping wells, even those with liquid columns so high that they occasionally flow out of the casing annulus. Low-pressure gas wells that will not flow against the hydrostatic head of a tubing full of oil, as used in a tubing displacement or formation inhibitor squeeze-type treatment. High-pressure flowing wells that are difficult to pump fluid into because of high formation pressure. The annular area of multiple completion wells. Typical field data are presented to show the effects of corrosion inhibitor treatments with the weighted inhibitor in several different fields. INTRODUCTION THE TERM ‘HIGH-DENSITY CORROSION INHIBITOR’ is used to designate those formulations that have been coupled with a weighting agent to make the product heavy enough to fall through well fluids. The connotation has generally been narrowed even further to include only those liquid products that will fall through an oil column and into or through a water column at the bottom of a well and will eventually be decoupled from the weighting agent. The decoupled inhibitor will then rise to the oil-water interface and enter the tubing through the tubing perforations if the, well is under production. The need for a high-density corrosion inhibitor has been recognized almost since the initiation of corrosion inhibitors into down-hole corrosion mitigation work. The stick inhibitor was probably the earliest form of a high-density corrosion inhibitor. It consisted essentially of a conventional inhibitor mixed and/or intermingled with a resinous, or wax, substance and barite. The entire mix was heated above the melting point of the wax and then cast into sticks., when cooled below the melting point of the wax, the stick attained a semi-rigid form. The barite provided the additional weight for the stick. Products made by crushing the inhibitor sticks were also used in treating down the casing annulus of pumping wells. Encapsulated inhibitors have also been used in an effort to facilitate the application of the inhibitor to the area needing protection, Development of a high-density liquid corrosion inhibitor has been a logical sequence of these earlier developments. In other words, it was the recognition of the need for such a product and the development of a product to meet that need. The high-density liquid corrosion inhibitor provided the industry with a product containing most of the more desirable characteristics of the stick and crushed inhibitors and without many of their undesirable features. Widely Accepted by the Oil Industry The use of high-density liquid corrosion inhibitors has been widely accepted by the oil production industry, The first well treatments with high-density inhibitors were made about five years ago.

Status of Downhole Corrosion In the East Texas Field—A Report of NACE Technical Unit Committee T-1C On Sweet Oil Well Corrosion. By Task Group T-1C-5 On East Texas Field Corrosion

Status of Downhole Corrosion In the East Texas Field—A Report of NACE Technical Unit Committee T-1C On Sweet Oil Well Corrosion. By Task Group T-1C-5 On East Texas Field Corrosion