Sour Gas Wells Research Articles

Innovative Critical Sour Gas Extended Production Test Through Surface Coiled Tubing

Summary This paper describes the deliverability test of a critical, sour, natural-gas well that uses coiled tubing as a surface pipeline. Conventional production deliverability tests are constrained by regulatory limitations on emissions and flaring, affecting test duration and reservoir evaluation. Conventional tests also carry significant environmental impact, and the lost revenue from flared gas hampers the economic justification of the test. This paper describes the concept, the background analysis, and the field production test. A safety-focused procedure was developed using surface coiled tubing for in-line testing of high-rate, critical, sour gas wells. This prototype method allows a proper evaluation of a well without the commitment and installation of a permanent pipeline, the volume restraint imposed by regulatory limitations, harm to the environment, and compromising economic value. This method of well production deliverability tests is projected to become an attractive alternative for the Alberta oil and gas industry.

ALLEGHENY LUDLUM ALLOY 255

Abstract Allegheny Ludlum alloy 255 is a high-strength duplex stainless steel. It combines high mechanical strength, ductility, and hardness with excellent resistance to corrosion and erosion. Under most conditions of service, its corrosion resistance is superior to that of the fully austenitic AISI type 304, 316, and 317L stainless steels. Its many uses include marine scrubbers, desalination equipment, sulfuric acid production, wet phosphoric acid production, mild sour gas wells, urea production, and applications in the pulp and paper industry. This datasheet provides information on composition, physical properties, hardness, and tensile properties as well as fracture toughness. It also includes information on high temperature performance and corrosion resistance as well as forming, machining, and joining. Filing Code: SS-786. Producer or source: Allegheny Ludlum Corporation. Originally published May 2000, revised June 2002.

Lead Deposits in Dutch Natural Gas Systems

Summary During the production of natural gas from Dutch Rotliegend and Kupferschiefer sediments that are next to "conventional" carbonate and sulphate scales, lead deposits sometimes also form. These deposits, which vary in composition from galena (lead sulphide) to elemental (metallic) to lead and complex lead (hydr)oxides, may form a serious threat to operations because they tend to block production equipment or injection pumps and tubing. In some cases, radioactive lead (lead-210 with a half-life of 22.3 years) is incorporated into these compounds at levels greater than regulatory concern, which necessitates additional safety measures during operations and maintenance. In sour gas wells, the deposition of galena can be explained by local supersaturation (caused by a sudden temperature or pressure drop) where bisulphide anions react with lead cations in the produced water, in which concentrations of up to 150 mg lead per liter brine have been detected. In the absence of hydrogen sulphide and even in "dry" gas wells, the deposition of metallic lead has been observed locally at rates of 10 g/D or more. An electrochemical mechanism is held responsible for lead deposition on carbon steel tubing: iron from the tube wall is oxidized by lead ions in solution, leading to corrosion of the wall and deposition of lead scales in thicknesses of 10 mm or more. Under unfavourable conditions or during maintenance operations, metallic lead is easily converted into secondary lead minerals. Detailed knowledge on the geological origin, the transport pathways to surface facilities, and the mechanisms of lead scale formation might enable the future development of techniques that can prevent lead deposition.

New Sour Gas Requirements for Alberta

Introduction The sour gas industry has been active in Alberta for some 50 years. About one-third of the remaining reserves of gas contain hydrogen sulphide and are thereby considered sour gas. The future potential reserves of Alberta are estimated to range from 2,000 to 4,000 billion cubic metres and it is anticipated that up to three quarters of these could be found in geological regions that typically contain hydrogen sulphide. For the Western Canadian Sedimentary Basin, future potential reserves will be much greater, and a significant percentage may be sour. The Energy and Utilities Board (EUB) is responsible for the approval of proposed sour gas facilities in the Province of Alberta and for the regulation of sour gas facilities and operations. Sour gas is very toxic to humans and animals at relatively low concentrations. Therefore, the exploration for and production of sour gas must be undertaken with specialized equipment and procedures to assure worker and public safety, as well as protection of the environment. As a result of increasing concerns regarding growth and operation of sour gas wells and facilities near both rural and urban development, a review of the adequacy of current regulatory requirements was deemed desirable by the EUB. The EUB wanted this review to include the widest spectrum of input from those stakeholders ultimately affected by sour gas development, and in particular, the general public living in sour gas areas. To conduct this review, the EUB, in January, 2000, formed an Advisory Committee on Public Safety and Sour Gas (the Advisory Committee) to review and make recommendations respecting the sour gas regulatory system. The Advisory Committee was made up of 22 members, reflecting a broad cross-section of stakeholders affected by sour gas development. It also included experts from disciplines such as risk management and health. The result was a committee with members from the public, including First Nations, municipalities, the local development industry, regional health authorities, relevant government departments, universities, and the sour gas industry. The Advisory Committee's mandate centred on a review and assessment of public health and safety-related requirements currently being applied to the approval, development, and operation of sour gas facilities in Alberta. Although the Committee's focus was on public health and safety, many of its recommendations are broad in nature and have the potential to address essentially all concerns related to sour gas. The Advisory Committee used a variety of methods to improve its understanding of the current regulatory system and to receive input into its effectiveness. These included presentations by a number of experts on various related issues, a series of regional discussion sessions in twelve provincial locations directly affected by sour gas development, meetings in First Nations and Metis communities, a random telephone survey, response forms, and written submissions. The Advisory Committee then prepared what it called a Directions document setting out the direction the Committee was moving towards in terms of its recommendations. It then went back to the communities and sought input on the Directions document.

Detonation Flame Arrester Qualifying Application Parameters For Explosion Prevention In Vapour Handling Systems

Abstract Compliance with air quality initiatives often involves the installation of a vapour collection system (VCS). The purpose of a VCS is to collect and direct vapours to a flare, incinerator or recovery unit. This practice creates a hazardous situation wherein an explosive vapour is exposed to an ignition source. This paper addresses the parameters of flame propagation within pipes and for operation of a Detonation Flame Arrester. The paper examines the division of responsibility between the end user and the manufacturer for the proper selection or proof of capability in each parameter. There are ten factors in creating the most severe flame front possible in a practical, full-sized piping system. They are: gas type, gas/air mixture, preignition pressure, temperature of the ignition source, temperature of the mixture, ignition location, pipe configuration, pipe size (larger line sizes than arrester size), protected-side restrictions and endurance to stabilized flame. Many certification standards define the acceptance testing of detonation flame arresters. They have been evolving and improving over the past two decades. A summary is made of which flame propagation parameters are addressed by various standards. Application reviews and installation in operating conditions using these parameters would have a significant impact on operational safety. The critical variables within the control of industry are outlined and qualified. When these parameters are applied, new levels of confidence would be created and the current high frequency of vapour transportation explosions reduced. Introduction Interest in the nature of vapour line explosions in Alberta, Canada began in earnest in the 1960s when, for environmental reasons, operators of oil and sour gas wells were required to collect vapours and burn them in flare stacks. Although these actions resulted in increased protection of the environment, they also subjected the workers and equipment owners in the oil industry to increased hazards from storage tank explosions. Prior to 1990 approximately 30 explosions per year occurred in Alberta alone, with each costing approximately $100,000 US or more in lost production and equipment replacement. Ironically, the cause of these explosions was directly attributable to the misapplication of equipment that is designed to stop an explosion from occurring-the "Flame Arrester." This passive device is the first line of defence against flame propagation from a flare to a storage tank. Conventional flame arresters designed for "end-of-line" applications and incorrectly located in pipes, produced a dismal operation performance record. Some explosions which occurred outside of Canada were the U.S. Green Lake barges (1983), a tanker in Malaysia (1992), Australian Coode Island storage tanks (1991), a tanker (1989), and a barge (1992) in the Houston ship channel. Practical and theoretical knowledge of flame propagation in piping systems, along with the technology to arrest such a flame has increased considerably in the last 15 years. A research program was started which dealt with flame propagation prevention technology and the development of reliable Detonation Flame Arrester (DFA) devices. Since 1985 activities included comprehensive explosion investigations(3), an analysis of ten Alberta oil field explosions(2), and the outlining of industry demands for flame arrester design parameters.

The Effect of Sulfur Deposition on Gaswell Inflow Performance

Summary Deposition of solid elemental sulfur in the formation may significantly reduce the inflow performance of sour-gas wells. The key operational and reservoir parameters that influence the magnitude of impairment by sulfur deposition were identified through the derivation of an analytical expression for the rate of sulfur buildup assuming idealized flow conditions. A methodology for the use of conventional, black-oil reservoir simulators was subsequently developed to permit the investigation of sulfur-deposition processes for specific reservoir descriptions and well operations. The rate of sulfur buildup in the formation was shown to be inversely proportional to the square of the radial distance from the well. As a consequence, the magnitude of sulfur deposition is highly sensitive to well skin— the lower the skin, the farther away from the well the deposition occurs and the lower the sulfur-buildup rate. Nonuniform deposition over the pay interval (owing to reservoir layering or uneven stimulation) was shown to accelerate the impact of sulfur deposition. A field case involving early decline in well production caused by sulfur deposition was successfully history-matched with the simulation model developed in this study.

A Method for Blowout-Rate Prediction for Sour-Gas Wells, Oldenburg Fields, Germany

Summary In view of the toxicity of H2S, sour-gas production has to be carefully planned for safe operation. For the determination of safe evacuation distances in the unlikely event of an accident, well-blowout conditions had to be investigated. A methodology for predicting blowout rates from sour-gas wells in the south Oldenburg area in Germany is presented. Flow under sonic conditions, wellbore dynamics, reservoir capacities and their interdependencies control the fluid movement. Generally the blowout rates have been calculated by superimposing reservoir and tubing performance curves (based on steady-state correlations). This approach predicts lower short-term transient rates than actually occurs. A finite-element pipe-rupture model for ultrashort-term transient rate calculations is used. A coupling mechanism between these results and a reservoir simulator with a steady-state vertical-flow-performance correlation is then defined. A time-based switching criterion is determined iteratively for each situation when the flow goes subsonic, and traditional well outflow models can be used.

Coil Tubing Plug Retrieval/Fishing Operations On Deep, High Pressure Sour Wells

Abstract This paper discusses coil tubing operations performed on three sour gas wells in which coil tubing was used to retrieve plugs where conventional wireline methods proved ineffective. All three wells are located in the Obed Field of Alberta, which produces high pressure sour gas. The field was suspended in March 1992 with wireline plugs set to isolate the down-hole formation. All of the wells had severe corrosion problems prior to suspension, making plug setting and retrieval difficult. Coil tubing offered the versatility of jetting and circulating, allowing access to the down-hole plugs in a sloughing scale environment. On the first two reactivations, coil tubing was used for descaling tubing and washing onto plugs. During the third reactivation, the coil tubing was parted, leaving 3,000 m of 31.8 mm coil tubing (CT) down-hole. The 31.8 mm CT was successfully retrieved using 50.8 mm CT in conjunction with wireline chemical cutters. Introduction The Obed Field is located near Hinton, Alberta. The field was purchased and reactivated by Chevron Canada Resources in August 1992. The field is comprised of five producing wells, three of which are completed in the Nisku formation and two in the Leduc formation. The wells are approximately 4,000 m deep and produce gas with 26–33% H2S and 6–9% CO2. Bottom-hole static pressures for the wells range from 35 to 38 MPa. The tubing in all of the wells is 114.3 mm, L-80 VAM ACE with 88.9 mm VAM ACE corrosion resistant alloy (lncoloy/Hasteloy) tailpipe. Figures 1, 2, and 3 are schematics of the wells. All of the wells have a history of severe scale and corrosion problems. Prior to being suspended in March 1992, the wells had been on a Diaryl Disulfide (DADS) batch treatment program for sulphur deposition prevention. In August 1992, attempts were made to retrieve the down-hole wireline set plugs from three wells. All three plugs were leaking and could not be pulled by conventional wireline methods due to scale buildup. Some sulphur buildup was encountered down to 1,000 m, with a mix of carbonate and iron sulphide scale existing from 2,000 m to bottom. Options Available to Retrieve Plugs When Chevron reactivated the Obed Field, it was assumed that the plugs could be retrieved using conventional wire line methods. Normally, plug retrieval using wireline is quite effective in vertical wells wiLh up to 60 ° deviation. The following options were available for scale control, plug retrieval and fishing operations:Wireline prong/plug retrieval.Wireline bailing for scale removal.Wireline fishing.Coil tubing jetting/acid washing for descaling tubing.Coil tubing used for washing over fish.Coil tubing used to clean out sloughed scale and pull prongs/plugs. Initially, pulling the prongs and plugs with wireline techniques was selected, since it was the most economical and, historically, had been successful in the Obed field. Initial runs were unsuccessful due to sloughed scale which made it impossible to reach the prongs/plugs. Consequently, an attempt was made to bail out the fill, but this also proved to be ineffective.

Coil Tubing Fishing Operation On a Deep, High Pressure, Sour Gas Well

Abstract The use of coil tubing in fishing operations has been limited to date. This paper discusses a coil tubing fishing operation on a 4000 m, 30% H2S gas well with 27 MPa surface pressure. A 12.5 metre wireline tool string was stuck inside the production tubing at 1770 m, with 76 m of elemental sulphur fill on top. The need for 23 m of lubricator during coil tubing fishing operations was eliminated by designing a pump through Pressure Deployment System, along with a pump-off sub. Problems encountered with the Pressure Deployment BOPs will necessitate periodic inspection of the BOP stack on future high pressure, sour well work. Advances in coil tubing technology have made coil tubing an economical alternative for many oil field operations. Fishing operations can now be performed on live wells without long sections of lubricator. Coil tubing has increased to 88.9 mm (3 1/2") in size, has become more H2S resistant and is now continuous without butt welds. The components of the coil tubing unit, such as the injector have also increased in strength allowing work in deeper and higher pressure wells. Introduction Esso's Obed Field near Hinton, Alberta is comprised of five sour gas wells, three of which are completed in the Nisku formation and the remaining two in the Leduc formation. A gauge ring with a junk catcher was run into Esso et al. Obed 11-13-54-23 W5 in an attempt to determine the amount of sulphur and iron sulphide scale buildup on the 114.3 mm tubing. The gauge ring became stuck due to sulphur scale buildup at 1770 m and was left in the hole. An unsuccessful attempt was made to fish for the gauge ring using braided line. During the fishing attempt the fish could not be pulled free and the fishing tool would not release from the fish so the braided line was pulled out of the rope socket. This left a resulting fish of 12.5 m in the well. An impression block run later revealed that 76 m of sulphur had piled on top of the fish. This 4000 m, 8% CO2, 30% H2S gas well had a bottom hole pressure of 38 MPa and 27 MPa surface pressure. Figure I is a schematic of the well, FIGURE 1: Subsurface schematic: Esso et al. OBED 11-13-54-23 WSM. (Available in full paper) wellbore, shear events near the well bore (combined P and S phases, too close to be distinguished), or shear events far away from the wellbore (S phase only, P phase completely absorbed). It is interesting to note that most of the signals are oriented within the N30–40 °E window (Figure 6). which is close to the expected orientation of the main fracture. The results also show that the best polarization is obtained within the first quarter-period of the wave and degenerates quickly afterwards. This can be explained if one assumes that the events are occurring close to the wellbore. The first part of the waveform would be mostly a P-wave that would become gradually contaminated by S-waves.

Comparison between thermal decomposition and photosplitting of H 2S over V xS y supported on oxides at 450–550°C in a static system

Hydrogen sulfide is present in sour gas wells or produced in hydrodesulfurization of high sulfur fossil fuels. The recovery of hydrogen in addition to elemental sulfur could become a very important industrial process with economic and environmental advantages. Thermal decomposition and photosplitting of H 2S was carried out in a cylindrical photothermal furnace using vanadium sulfide on Al 2O 3, TiO 2, ZnO and ZnS as catalyst. A 30 ml pyrex glass reaction vessel, with light flux of 130 mW cm −2 has been studied in a static system. The conversion increased to more than 7.5% in the case of V x S y /ZnS, while the photoactivation of the catalyst increases the conversion of H 2S up to 40% depending on the temperature and supporting materials of V x S y . Absorption of photons by these catalysts at high temperature has been considered assuming that the molecules change to their excited states and photoproduce electrons and holes at the surface. The mechanism for splitting of H 2S to hydrogen is the enhancing reaction by direct action of solar radiation.

Successful Inhibition of Deep, Hot, Sour-Gas Wells

Summary The sour-gas wells in the Big Escambia Creek (BEC) field of South Alabama have a production environment that consists of 280°F, 21% H2S, 40% CO2, and up to 190, 000 ppm chlorides in the produced water. The highly corrosive conditions demand the ultimate in a corrosion mitigation program to produce these wells safely and economically. This paper describes the background, technical development, and results of the downhole and gathering-system corrosion inhibition and monitoring programs: continuous downhole inhibition by means of annular injection of a water-dispersible inhibitor in the most aggressive wells; downhole batch treatments with nitrified tubing displacements of an oil-soluble inhibitor in the remaining wells; continuous injection of a water-dispersible inhibitor in the gathering lines to augment the batch treatments and in selected highly corrosive wells; monitoring of inhibitor residuals and plotting of trends to ensure the effectiveness of downhole treatments and to optimize injection rates; and flowline calipers and hydrotests to monitor the gathering-line inhibition programs. The paper also describes the computerized approach used in designing, calculating, and updating both the continuous downhole injection system and the nitrified batch treatments. The success of the inhibition and monitoring program is demonstrated by the tubing life achieved, field data on inhibitor residuals, and flowline and downhole calipers. The technical data presented will aid in the design and implementation of successful inhibition programs for highly corrosive production environments.

Interlaboratory Testing of Seven Alloys for SSC Resistance by the Double Cantilever Beam Method

Abstract Seven alloys for deep sour gas wells were evaluated for sulfide stress cracking resistance by the double cantilever beam (DCB) method. Representatives of 20 laboratories participated in one or both of two round-robin testing programs. These were conducted in support of the successful effort to include the DCB test in an expanded NACE test method, TM0177-90 (D). Test materials included cast and wrought products, low-alloy and stainless steels, and non-ferrous alloys. The test results reveal generally minor variation of KISSC within data sets from individual laboratories but rather high variation between laboratories. This latter variation is greatest for the two cast alloys and lowest for wrought stainless, Ni- and Ti- base alloys. The variation between laboratories for C-90 is attributed mainly to differences in initial arm displacement; on average, KISSC rises approximately 0.2 ksi√in. per 0.001-in. increase in arm displacement. At fixed arm displacement, the DCB test for C-90 exhibits good repr...

Corrosion-Resistant Alloys for Hot, Deep, Sour Wells: Properties and Experience

Summary Nickel-based, corrosion-resistant alloys (CRA's) were subjected to extensive corrosion testing and evaluation for potential use in hot, deep, sour wells. The Ni-Cr-Mo-W system was used in sour-gas wells in south Mississippi, Wyoming, and Mobile Bay. Corrosion data, mechanical properties, and resistance to environmental stress cracking are described for several oil country tubular goods (OCTG). Better understanding of metallurgical factors and of the role of alloying for enhanced resistance to corrosion, along with advances in materials processing, are reviewed in terms of their impact on OCTG product reliability, improved safety, and cost-effectiveness.

Application of Alkylnaphthalene Absorption Oil as a Sulfur Solvent in Sour-Gas Wells

Summary Elemental sulfur is soluble in sour gas and often precipitates in sour-gas wells during production. Prevention of sulfur deposition in the production equipment requires the application of a sulfur solvent. An aqueous alkaline solvent is inadequate at increasing formation-water inflow resulting in severe carbonate precipitation. The new solvent is based on a mixture of alkylnaphthalenes diluted in a mineral oil. Both can combine physically with the precipitated sulfur. The performance of the solvent during circulation, its regeneration, and its behavior in corrosion inhibition is outlined. Application of this solvent improved the production of the treated sour-gas wells.

Iron Control in West Texas Sour-Gas Wells Provides Sustained Production Increases

Summary Permian Basin operators have recorded sustained production increases bypreventing production increases by preventing precipitation of iron sulfide andother precipitation of iron sulfide and other sulfur-containing species. Thisimprovement has resulted largely from cleaning out tubing before acidizing andfrom preventing the precipitation of ferrous sulfide and the formation ofelemental sulfur by simultaneous use of iron chelants and sulfide-controlagents. Previously used methods gave only temporary production increases thatterminated production increases that terminated when iron dissolved by thestimulation acid reprecipitated in the pay zone and damaged the formation afterthe stimulation acid was spent. This paper describes a method to optimize ironsulfide control, methods to minimize reprecipitation. and case histories fromthe Permian Basin that show improved methods to control iron in sour-wellenvironments. Introduction Stimulating wells with acid was first reported in 1896. Acid was proposed tobe injected into the formation to dissolve the rock and to improve the flow ofoil to the wellbore area. This method offered advantages over the then currentstimulation method of "shooting" the well. Although the use of an aggressive fluid, HCl, offers many advantages thathave resulted in its widespread use, it does have several disadvantages. Thispaper discusses the disadvantage of the high solubility of iron containingcompounds in HCl: the iron dissolved from the tubulars by the stimulation acidcan be redeposited as a precipitate in the pay zone, damaging the formationwhen the HCl is consumed. Formation damage in sweet wells occurs when ferric ion is precipitated fromsolution. The iron compounds dissolved during an acid treatment in sweet wellscan place both ferric ion (Fe) and ferrous ion (Fe) in solution. The formationis damaged because the pH of spent acid is about 4.0 and the solubility offerric ion is very high in fluids with pH values below 2.5 and very low influids with pH values above about 3.5. (The values between 2.5 and 3.5 willhold some iron in solution, but to a lesser extent.) Ferrous ion does not causeproblems in sweet wells because its precipitation does not occur until a pH ofabout 7.0 is reached. In recent years, several methods have been used successfully to control ironreprecipitation in sweet wells. Some common methods include the use ofbuffering agents to hold the pH of the fluid below 2.5, chelating agents toreact with the ferric ion to provide soluble complexes, reducing agents toprovide soluble complexes, reducing agents to modify the oxidation state offerric ion, and combinations of these methods. These systems have found utilitywhen acidizing fluids are applied to sweet wells where ferric ion has beendissolved, but the reprecipitation problem is not fully remedied if sulfidesare present. This results because the buffering systems, some chelating agents, and reducing agents fail to prevent reprecipitation of iron with H S to formiron sulfide and, in some cases, elemental sulfur. Damage From Scale Iron sulfide reprecipitation in the formation (from spent-acid solution) isthe most probable reason that acid jobs fail to achieve probable reason thatacid jobs fail to achieve sustained production in sour producing wells orincreased injectivity in injection wells that carry sulfides. The primarysource of the reprecipitated iron sulfide is iron containing sulfide scalesdissolved from the tubulars by the acidizing fluid. Wells that produce or inject sulfidecontaining fluids contain iron sulfidescales or iron sulfide corrosion products. The type of iron sulfide depositeddepends on a number of considerations, including temperature, brine salinity, and the presence of other gases, such as CO2. Mackinawite (Fe S), troilite(FeS), or pyrrhotite (Fe S) is almost always found on tubular surfaces. Pyrite(FeS) and marcasite (FeS) are also Pyrite (FeS) and marcasite (FeS) are alsofrequently found. Another complication is that one or more types of ironsulfide will precipitate and undergo further reaction with precipitate andundergo further reaction with either H S or the iron surface to create layersof different compositions of iron sulfide. Each compound has its own specificsolubility. The general trend is that compounds with approximately one-to-onestoichiometry will be readily soluble and have rapid reaction rates with HCl, while compounds with higher sulfur stoichiometries will have lower solubilityand much slower reaction rates (Table 1). It is a mistake to assume that wellscontaining moderate to small amounts of H S will form less scale or corrosionproduct on the tubulars than wells with higher H S concentrations. What isknown is that most of these sulfide scales are soluble to some degree in acidicstimulation fluids. These scales or corrosion products can be redeposited inthe formation, products can be redeposited in the formation, causingdamage. The magnitude of the problem is often not recognized. Iron sulfide scalescan react with HCl to an extent that effectively reduces the acid concentrationto less than 1% HCl content. These fluids, which are high in ferrous iron and HS content, will further spend when contacted with the formation containingcalcium carbonate or other acid-consuming species. JPT P. 603

Iron Control Provides Sustained Production Increase In Wells Containing Sour Gas

Abstract Acid stimulation of wells containing hydrogen sulphide has in some cases resulted in short-lived production increases. The rapid decline in production has been thought to be related to reprecipitation of sulphur-containing species which reduce the flow of hydrocarbons when the well is placed on production. By using agents which interact with both iron ions in solution and hydrogen sulphide, precipitation of iron sulphide and elemental sulphur can be controlled and damage to the formation permeability can be reduced. The result of proper control of these sulphur-containing species is to provide the operator with sustained production increases after acidizing. This paper will discuss the mechanisms of damage, current iron control methods, solutions to the deficiencies 0f the currently used methods, and case histories showing use of improved methods of iron control in hydrogen sulphide environments. Introduction The use of acid to improve the production of hydrocarbons from subterranean formations as an effective method of stimulation was introduced in 1896(1). In these processes, acid was injected into the formation to dissolve the rock matrix to improve the now of hydrocarbons from the formation to the wellbore area for removal. Hydrochloric acid (HCl), an aggressive fluid, has many advantages which have resulted in its common use as a stimulation fluid. However, as such, an aggressive fluid does have some disadvantages. The major disadvantage pertinent to this paper is the high solubility in HCl solutions of iron containing minerals, many of which will reprecipitate when the acid content of the fluid decreases(2). Several methods have been used with success in controlling the repredpitation of iron in sweet wells. Some more commonly used materials have included buffering agents, chelating agents, reducing agents, and combinations of the above systems, These systems are designed to control the reprecipitation of ferric ions as hydrated ferric oxides. 'This ion has great solubility in fluids with pH values lower than about 2.5, but rapidly becomes insoluble in fluids with pH values above 2.5(3). This problem occurs because the normal pH of a spent acid fluid is about 4.0. Buffering agents can maintain a high acid content of the spent acid fluid at pH values below 2.5 for some time, and when used with chelating agents, have allowed spent acid fluids to retain high concentrations of ferric ion in solution(4,5). Reducing agents chemically convert ferric ion to ferrous ion(6,7,8). Ferrous ion does not precipitate at the pH of spent acid fluid. These systems have been shown to be effective in sweet wells; however, the problem becomes severe when sulphides are present. 'This is due to the failure of buffering systems, reducing agents, and some chelating agents to prevent the reprecipitation and reaction of iron solution species with hydrogen sulphide. Scale Sources The major source of possible damage to sour gas wells after acidizing is the reprecipitation of iron sulphide in the formation from the spent acid fluid. The source of this compound is from the redissolution, by the stimulation acid, of existing iron-containing sulphides on the tubular(9).

An Evaluation Of Corrosion Monitoring Techniques For Measuring Corrosion Inhibitor Performance In Sour Gas Gathering Systems

Abstract Amoco Canada Petroleum Ltd. operates approximately 50 sour gas wells in the Fox Creek area of Alberta. Historically, anodic polarization probes and corrosion inhibitor residual measurements have been utilized to monitor corrosion inhibitor performance and to verify system inhibition. In this study, a wellhead test loop was installed to compare various corrosion monitoring techniques and to determine the effectiveness and cost performance of several new corrosion inhibitors. Anodic polarization was useful for measuring relative corrosion rates and relative inhibitor performance. In view of the differences observed between anodic polarization measurements and corrosion coupons, the former technique should be used in conjunction with corrosion coupons, particularly when evaluating new corrosion inhibitors. In the test protocol, electric resistance probes were not useful for short-term inhibitor evaluation, although they warrant further investigation as a long-term monitoring technique in systems where the inhibition criteria have been previously established. The hydrogen probe was not sensitive or responsive to changes in corrosion inhibitors, or inhibitor injection rates. Although the exposure time of the corrosion coupons was typically six to eight days, the polished rod coupons provided valuable metallurgical response to the various inhibitors tested. Finally, corrosion inhibitor residuals were useful for verification of inhibitor injection rates and correlated well with the optimum concentrations determined by laboratory studies. Introduction Corrosion History Production from the Kaybob South Beaverhill Lake gas field began in 1968, with initial projections for low water production. However, severe water coning occurred immediately and water production rates were much higher than originally anticipated. As the water rates increased, so did the chloride content of the produced water. The combination of these two factors resulted in several internal corrosion problems. The resulting failures were caused by isolated pitting attack in the bottom quadrant of the pipeline in low velocity areas, and in low elevation areas where produced fluids accumulated. The design of the gas gathering system precluded any form of pigging or detailed line inspection using smart pigs. Consequently, the development of an effective water soluble or highly water dispersible corrosion inhibitor was required to control internal corrosion in the gas gathering system. Initially, control of the chemical injection program was extremely difficult due to two factors a continually increasing water production rate and infrequent well testing, as well as limited access points for obtaining water samples for inhibitor residual testing. Line failures continued to be a problem until an extensive testing program was initiated, which provided the information required to predict and set maximum flow rates to stabilize water production. A water soluble/dispersible inhibitor was developed during the same period and the combination of these two factors resulted in the successful control of internal corrosion problems in the Kaybob South gas gathering system. Throughout the life of the field, the following factors have significantly contributed to the development of a successful corrosion inhibition program.Extensive well testing allowed ongoing monitoring and projection of water production rates.The development of a corrosion inhibitor which exhibited significant water solubility dispensability.

What Is a Sour Environment?

Summary The mere presence of H2S in a wet oil or gas system may cause either weightloss corrosion or sulfide stress cracking (SSC) of carbon and low-alloy steels.in addition, H2S may enhance chloride stress corrosion cracking (SCC) ofstainless steels and other higher alloys. The likelihood that these phenomenawill occur depends on the severity of the environment. This paper dealsprimarily with sulfide SSC. primarily with sulfide SSC. Introduction The evaluation of a specific oil and gas environment is often difficult butmay be critical to the successful operation of the field in question. The" sour environment" definition depends upon both the metallic-alloycharacteristics and the environmental conditions. The Natl. Assn. of Corrosion Engineers (NACE) does provide some guidance inmaking this critical analysis. The NACE definition of sour environment has notchanged since 1978 and is still appropriate for most carbon and low-alloysteels. However, it does not appear to be appropriate for high-strength steelsor the many corrosion-resistant alloys (CRA's) now in use. History Many new fields in the oil and gas industry were developed in the 1950's and1960's. In some of these fields. particularly in Canada, the H2S content in thegas phase was higher and the environmental conditions were more severe thanthose experienced during the development of sour-oil fields then inoperation. Metal failures began to occur in the sourgas wells and surface equipment. The industry quickly began research and established committees to findsolutions to the problem. Laboratory and field data provided problem. Laboratory and field data provided clues on which environments caused equipmentfailures and why. Predicting the environmental severity necessary to causefailures was complex and involved evaluating environmental conditions (such asthe concentration of H2S present, pressure, temperature, and the presence orabsence of liquid water) and alloy characteristics (including chemistry, heattreatment, strength, and manufacturing and service history). NACE Definition of Sour Environment NACE Standard MR0175-881 provides guidelines for defining a sour environmentfor the general selection of carbon and lowalloy steels and is based onindustry experience and laboratory data available when it was developed. Thisdefinition states that the 0.05-psia [0.34-kPaj H2S partial pressure in the gasphase distinguishes SSC pressure in the gas phase distinguishes SSC failuresfrom no failures in susceptible carbon and low-alloy steels. Standard MR0175-88also includes two figures that show the determination of H2S partial pressurefrom the total system pressure and the pressure from the total system pressureand the H2S concentration. The standard has not been altered but does include acautionary note that states that high-strength carrion and low-alloy steels mayfail at H2S partial pressures less than 0.05 psia [less than 0.35 kPai, pressures less than 0.05 psia [less than 0.35 kPai, particularly at lowtemperatures. particularly at low temperatures. At the time Standard MR0175-88was prepared, industry field experience had prepared, industry field experiencehad demonstrated that the presence of a continuous inhibitive oil phase wasbeneficial at low pressures. it was thought that the oil pressures. it wasthought that the oil inhibited overall corrosion and reduced the tendenency forSSC. Conversely. the absence of hydrocarbon liquids increased the risk of SSCin susceptible carbon and low-alloy steels. Thus, separate figures weredeveloped for gas and multiphase systems. These figures were identical at totalsystem pressures >265 psia [>1.8 MPa]. pressures >265 psia[>1.8 MPa]. Fortunately, most carbon and low-alloy steels do becomeresistant to SSC at some elevated temperature that depends on the steel'schemical composition. hardness (strength), heat treatment, and prior servicehistory. NACE provided guidance or the use of the most common higher-strengthAPI tubulars, such as the recommended minimum temperature for API Specification5-CT grades shown in Table 1. Comments on NACE Definition The figures in Standard MR0175-88 may be used as a guide for determiningwhether a particular gas is sour enough to cause SSC particular gas is sourenough to cause SSC of susceptible carbon and low-alloy steels. JPT P. 260

Environmental Method Controls Corrosion/Cracking in Mobile Bay

Summary This paper overviews the system installed to dehydrate produced sour gas onoffshore platforms in the lower Mobile Bay Mary Ann field. The system, asilica-gel bed-dehydration system, is the first such installation forproduction of offshore sour gas in our U.S. domestic operations. Discusses thedecisions made in developing the system and describes the system as it wasinstalled. Introduction The discovery of the lower Mobile Bay Mary Ann field in 1979 put into motionan enormous design and development effort to build the facilities required toproduce the newly found reserves. Many aspects of this project required newtechnology or new applications of existing technology. This paper presents onlyone of these cases: it defines the approach and outcome paper presents only oneof these cases: it defines the approach and outcome of a portion of the designeffort to protect the pipeline that transports the produced sour gas from theoffshore platforms to the onshore treating facility. The gas, as produced at the wellhead, is potentially very corrosive to thefacilities and the pipeline. The gas contains all the ingredients necessary forenvironmental cracking and severe metal-loss corrosion-H2S and CO2 atrelatively high partial pressures in contact with free water. The problemrequired an analysis of various techniques of corrosion/cracking control. Thesetechniques can be divided into three major approaches: metallurgical, mechanical, and environmental. One or a combination of these approaches wasused in all components of the production facilities. All facilities weredesigned for a 40-year life with production facilities. All facilities weredesigned for a 40-year life with zero catastrophic failures. Field Operations The lower Mobile Bay Mary Ann field, at the mouth of Mobile Bay, is the site of the discovery well for the offshore Alabama Norphlet formation. The firstcommercial production of natural gas from the Norphlet formation offshoreAlabama began in May 1988. Six Norphlet wells are drilled in the field. Theaverage depth of the wells is about 21,000 ft [6400 m] true vertical depth. Each well is capable of producing 10 to 20 MMscf/D [283x103 to 566x103 stdm3/d] of natural gas. The gas is dry, with significant concentrations of H2Sand CO2. Table 1 shows the produced-gas composition used to design theproduction facilities. The gas is produced offshore at the productionplatforms. Initial startup involved two wells on Platform 77B and one well onPlatform 76A. Fig. 1 is a general map of the field. Each platform is designedfor two sour-gas wells with a platform design capacity of 30 MMscf/D [850 stdm3/d]. A future platform, Platform 95E, will be designed for 40 MMscf/D[1.13x106 std m3/d]. Platform 76AUX is a central gathering/distributionplatform bridge connected to Platform 76A. Produced liquids, primarilycondensed water, are separated at the platforms Produced liquids, primarilycondensed water, are separated at the platforms and pumped to shore fordisposal. After separation, the produced gas is dehydrated on the offshoreplatforms and sent to the onshore plant for treating before sale. The onshoreplant consists of a treating unit, a dehydration unit [triethylene glycol(TEG)], a sulfur recovery unit, a tail-gas cleaning unit, and associatedutilities. The plant is designed to process 80 MMscf/D [2.27x 106 std m3/d] ofnatural gas. Fig. 2 illustrates process 80 MMscf/D [2.27x 106 std m3/d] ofnatural gas. Fig. 2 illustrates the overall field production process. Corrosion/Cracking Control: Methods Selection This discussion of the various corrosion control methods provides somebackground for the selection of dehydration as the primary means ofcorrosion/cracking protection for the sour-gas pipeline. With the metallurgicalapproach, setting rigid specifications in the design and construction of thepipelines and process facilities was the primary method of protection againstenvironmental cracking. To ensure conformance with these specifications, quality control, from the mill through construction, was tight. Among thespecifications used were NACE Standards MR-01-75, Sulfide Stress CrackingResistant Metallic Materials for oil Field Equipment, and TM-02-84, Evaluationof Pipeline Steels for Resistance to Step wise Cracking. Beyond thespecifications in these standards, increased chemistry control of theequivalent carbon content to reduce hardenability was enforced in manufacturingthe pipe used in the sour pipelines. pipelines. To combat corrosion, theprimary metallurgical approach was to select a pipe-wall thickness withsufficient corrosion allowance. pipe-wall thickness with sufficient corrosionallowance. JPT P. 62

Fatigue behaviour of steels with multiple notches. II. The effect of interaction between notches on the characteristics of plane bending fatigue: Wakahara, M., Kawagoishi, N. and Suenaga, K. Res. Rep. Fac. Eng., Kagoshima Univ. Nov. 1988 (30), 207–214 (in Japanese)

In recent years, aluminum alloy drill pipe are used more and more frequently in the exploration and development of the deep wells, ultra-deep wells and sour gas wells due to the high strength, light weight and corrosion resistance to H2S and CO2. However, the pitting and fracture failure sometimes occurred, resulting in giant economic losses and fatal disaster. In this study, the failure analysis of aluminum alloy drill pipe was addressed and the formation cause of the pits and parallel transvers cracks was investigated. Results show that the chemical composition and the regular mechanical properties (including tensile and impact properties) meet ISO 15546:2011 standard requirements. But the tensile strength of samples immersed in the mud environment is lower than that of ISO 15546:2011 standard requirements. Metallographic analysis results show intermittent ribbon Al6(MnFe) solid solution, S (CuMgAl2) phase and AlFeSi phase distributed on α solid solution. The failure cause of aluminum alloy drill pipe is mainly attributed to the brittleness sensitivity of intermittent banded second phase and inclusions to corrosive media from mud environment. Cracks and pits are prone to generate here. XRD and EDS analysis results of corrosion products and the pits bottom show that the main corrosion products are Al2O3, Al2S3, AlPO4, BaSO4 and CaCl5. S and Cl are from environment media. The microscopic morphology analysis results of the tensile and impact specimens fracture show that the fracture is the brittle fracture caused by the environmental medium.