Tubular Goods Research Articles

Capacitor discharge magnetization of oil country tubular goods: 37158 Moake, G.L.; Stanley, R.K. Electromagnetic Methods of Nondestructive Testing. Edited by William Lord. Nondestructive Testing Monographs and Tracts, Vol. 3, pp. 151–160. Gordon and Breach Science Publishers (1985)

Capacitor discharge magnetization of oil country tubular goods: 37158 Moake, G.L.; Stanley, R.K. Electromagnetic Methods of Nondestructive Testing. Edited by William Lord. Nondestructive Testing Monographs and Tracts, Vol. 3, pp. 151–160. Gordon and Breach Science Publishers (1985)

Basic principles of magnetic flux leakage inspection systems for the evaluation of oil country tubular goods 37157 Stanley, R.K. Electromagnetic Methods of Nondestructive Testing. Edited by William Lord. Nondestructive Testing Monographs and Tracts, Vol. 3, pp. 97–149. Gordon and Breach Science Publishers (1985)

Basic principles of magnetic flux leakage inspection systems for the evaluation of oil country tubular goods 37157 Stanley, R.K. Electromagnetic Methods of Nondestructive Testing. Edited by William Lord. Nondestructive Testing Monographs and Tracts, Vol. 3, pp. 97–149. Gordon and Breach Science Publishers (1985)

Influence of Microstructure on SSC Susceptibility of Low-Alloy, High-Strength Oil Country Tubular Goods

Abstract The influences of microstructural factors, such as a distribution of precipitates and internal strain after tempering, on sulfide stress cracking (SSC) susceptibilities are investigated. It is revealed that (1) a homogeneous dispersion of spheroidized fine carbides and (2) a reduction of locally concentrated internal strains during recovery and recrystallization are preferable for improving the SSC resistance of low-alloy steel. Microstructure refinement is effective in increasing Luders elongations and permits larger amounts of plastic deformation to initiate SSC. Regarding the maximum hardness or strength limitation for sour service, existence of the critical strain for SSC is discussed. Using the microstructure control technique, C-100 grade oil country tubular goods (OCTG) is developed. SSC susceptibilities of trial products are examined using various kinds of SSC evaluation methods. Characteristics and comparisons of test methods are also discussed.

The Importance of Correct Running and Handling Procedures for Premium Tubular Goods

Summary The demand and requirements for tubular goods to handle deeper wells with more hostile environments have resulted in increased popularity and widespread use of proprietary sour-service steel grades and corrosion-resistant alloys (CRA's) with premium connections. Because of the great potential economic disasters that could result if damaged tubulars are run in hostile environments, obtaining maximum performance from the tubulars is imperative. Improper handling and running damage can cause (1) unnecessary and excessive damage to the threaded areas, requiring field repair or rethreading; (2) failure of the tube—i.e., collapse, burst, small leaks, or fatigue; (3) leaks or connection parting (failure); and (4) catastrophic failure—such as blowouts, loss of well, loss of equipment, or loss of life. For adequate tubing and casing performance, equal emphasis should be focused on running and handling procedures, tubing, casing design, and materials selection. This paper discusses all phases of running and handling for premium tubular goods and presents supportive field data from three geographic areas.

Development of 110-ksi Grade OCTG With Good Resistance to Sulfide-Stress-Corrosion Cracking

Seven trial heats that were quenched and tempered into the C-110 strength range were tested for sulfide-stress-corrosion cracking (SSCC) resistance with three popular test procedures: the NACE tension, the Shell bent-beam, and the double-cantilever-beam (DCB) methods. One of the heats, containing 0.45% C, 0.6% Mn, 1.0% Cr, 0.8% Mo, 0.04% Nb, 0.05% V, and 0.03% Ti, was tempered at temperatures above 1,292F (700C) and satisfied the requirements for C-110, where the NACE threshold stress was set at a minimum of 80% of its specified minimum yield strength (SMYS).

Effects of Perforation-Entry Friction on Bottomhole Treating Analysis

Summary Analysis of field and laboratory data shows that variations in pressure drop caused by changing perforation-entry friction tends to influence the prediction of fracturing treatment performance. This paper presents experimental data on perforation-entry friction as it affects fracturing treatment design. Prefracturing treatment planning practices include examination of numerous treating-pressure charts to determine formation type curves, which are used to anticipate fracturing treatment performance and screenout modes. Perforation-entry friction may vary greatly because of erosion of the perforation and new-wellbore fracture, and this changing friction pressure is often not properly accounted for in planning. This paper presents discussion and data (laboratory and field) that show the degree of perforation erosion encountered in fracturing operations and proposed guidelines to determine when to alter pumping schedules to account for proppant erosion to perforations, cement sheath, and formation. Introduction Fluid rheology measurements, densimeters, and flowmeters, combined with recent advances in computing power, allow determination of bottomhole treating pressure (BHTP), pbht on a real-time basis. This pressure is actually the BHTP inside the casing. The true BHTP is the pressure inside the fracture. BHTP and formation bottomhole pressure (BHP) are used interchangeably. The missing link and principal unknown in hydraulic fracturing is fracture-entry friction, pfef. It is usually assumed to be equal to zero, to be a constant, or to be a negligible influence on fracture treating pressure. Fracture-entry friction is the total pressure drop experienced by the fluid from the casing through the perforation and perforation tunnel to the fracture tip. Perforation friction, pf, is the pressure drop of the fluid passing through the restriction of the perforation in the casing. Current technology can determine the fracturing pressure in the casing but may not properly account for the changing BHTP caused by changing pfef. This paper addresses the changing pfef that occurs during pumping of sand-laden slurries. Pioneering work by Nolte and Smith1 created increased industry awareness of the necessity for accurately determining formation BHP during a fracturing treatment. In an extension of Nolte and Smith's work. Conway et al.2 proposed the analysis and use of treating-pressure type curves to predict well type and screenout mode during the treatment. Many hydrocarbon zones are bounded by a delicate boundary layer that may be fractured by pressure a few hundred psi over design pressure. Analysis of the Nolte and Smith plot is used to determine whether the fracture has broken out of zone. Changing (decreasing) perforation friction pressure during a treatment can be interpreted on a Nolte and Smith plot as evidence of breaking out of zone. Eq. 1 is used to calculate BHTP:Equation 1 wherepbht=BHTP,pw=wellhead pressure.ph=hydrostatic pressure.pt=pressure caused by fluid friction in tubulars, andpfef=pressure caused by fracture-entry friction. Two calculated values are present in this equation, pt and pfef. Several recent papers3–5 described means by which the calculation of pt can be improved, particularly in the case of sand-laden slurries. Components of fracture-entry friction include perforation friction, cetnent-sheath friction, formation damage (resulting from perforating), and fracture friction. Fracture friction can be calculated and depends on the fracture treatment design and fracture width. Formation damage can be minimized by shooting under-balanced,6,7 by proper design of perforation schedule, and by remedial acid cleanup jobs. Cement-sheath friction owing to perforating damage and its erosive properties is shown to have only a minor effect on total perforation-entry friction when slurries are pumped. The major component of pfef is pf, which is detailed below. The other components of pfef are minor constituents. When sand-laden slurries are pumped at high differential pressure across perforations, pf changes constantly. Field and laboratory data have been combined to derive coefficients theoretically and empirically and to check this equation. The equation commonly used to predict pf isEquation 2 whereq=total flow rate,?=fluid density.np=number of perforations.d=perforation diameter, andKd=discharge coefficient. Erosion of perforations in tubular goods and the subsequent drop in pf are the main points of emphasis in this paper. Laboratory data show that perforation-friction changes alone can cause errors in interpretation of Nolte and Smith plots. Experimental Apparatus. Three series of tests were run that pumped sand-laden slurries through perforated casing. Sand slurries are referred to by their concentration - i.e., pounds of sand per gallon of gelled fluid. Sand concentrations varied from 2 to 20 lbm/gal [240 to 2400 kg/m3], and differential pressure across the perforations ranged up to 1,500 psi [10.4 MPa]. Apparatus. Three series of tests were run that pumped sand-laden slurries through perforated casing. Sand slurries are referred to by their concentration - i.e., pounds of sand per gallon of gelled fluid. Sand concentrations varied from 2 to 20 lbm/gal [240 to 2400 kg/m3], and differential pressure across the perforations ranged up to 1,500 psi [10.4 MPa].

Iron Control In Fracturing And Acidizing Operations

Abstract Investigative results from laboratory tests and field jobs show that iron presents a significant and complex problem in stimulation operations. Non-acidic or weakly acidic fracturing fluids are not detrimental from the aspect of dissolving and reprecipitating iron compounds. However, fracturing fluids usually contain a significant cancentration of dissolved and entrained oxygen which makes the fluid incompatible with formation water that contains ferrous ions in solution. The problem presented by an acidizing fluid differs from that presented by non-acidic or weakly acidic fracturing fluid. Acid dissolves iron compounds from equipment and flow lines as it is mixed and pumped to the formation. Acid may dissolve additional iron as it reacts with the formation. If acid does not contain an effective iron control system, dissolved iron precipitates. This precipitate may then accumulate as it is carried toward the wellbore during flowback. This accumulation of solids may plug natural and created permeability and have a detrimental effect on the recovery of the treating fluid and production. Chemicals and techniques that help ensure the compatibility of fracturing fluids and formation water are described. Iron control systems used in acidizing have properties that influence their effectiveness. The properties and effectiveness of the various systems are described so that a judicial selection of the most effective system can be made. Introduction Iron control problems are sometimes encountered when stimulating operations are conducted with weakly acidic or nonacidic fracturing fluids. The fracturing fluid ordinarily does not contain enough acid to dissolve iron and iron compounds from the well equipment or formation. Fracturing fluids, because of blending operations and viscosity of gelled fracturing fluids, will contain dissolved and entrained oxygen, which makes the fracturing fluid incompatible with formation waters that contain ferrous iron, Fe(2). The fracturing fluid mixes with the formation water. Oxygen in the fracturing fluid immediately oxidizes the ferrous iron, Fe (2), to ferric iron, Fe(3). The Fe(2) will remain in solution at pH levels up to about 7.5. The oxidation product, Fe(3), starts to precipitate at a pH of 2.5 and has completely precipitated when the pH reaches 3.5. The pH of the natural environment is usually greater than 3.5 and precipitation of Fe(3) occurs as the Fe(3) is formed by oxidation. Acidizing operations are usually conducted with highly acidic solutions. Acid corrosion inhibitors inhibit the reaction of acid on the metal contacted; however, they do not inhibit the reaction of the acid with iron compounds (rust, mill scale, siderite, and other iron compounds) to an appreciable extent. Acid dissolves these iron compounds as it is mixed and pumped through tubular goods to the formation. Iron content of the acid may possibly exceed 100 000 mg/I by the time it reaches the formation. This will depend on the condition of the pipe, the amount of pipe surface area contacted, concentration of acid used, and the temperature. Conditions may dictate a pre-clean job prior to the formation stimulation operation. This acid, containing iron in solution, flows into the formation, and dissolves additional iron before it is spent.

Hydraulic-Fracture-Treatment Design Simulation

Hydraulic fracturing is a technique for simulating wells completed in low-permeability reservoirs. The process involves the pressurization of an isolated perforated section of the wellbore with a viscous fluid until the induced stresses exceed the formation strength, which causes a failure and thus creates the fracture. Proppants are then pumped into the newly created fracture with viscous fracturing fluid as a carrier. Once initiated, the fracture propagates as additional fracturing fluid is injected. Following the release of the fracturing pressure, the proppants hold the fracture open and provide a conductive channel through which the reservoir fluids flow to the wellbore. Only vertical fractures are considered here. Hydraulic-fracturing simulators are used to design the treatment volume, proppant size and type, and pumping schedules to obtain the desired fracture geometry and conductivities. The pumping schedules are designed by running these simulators on a trial-and-error basis until a desired propped geometry is obtained that will ensure maximum proppant coverage at the end of pumping. With these propped fracture geometry and conductivity data, an economic estimate is usually made for the treatment for a given fracture length and an optimal design is selected for the maximum return of the well.

Heated Acids For Improved Stimulation

Abstract A simple and practical process has been developed to heat hydrochloric acid to improve its performance as an oil well stimulating agent. Heated acid is used in cold formations, such as cold dolomites, to increase the rate at which the formation is dissolved, thus improving flow capacities. The new technique heats the acid by causing an exothermic chemical reaction that uses a portion of the HCl as one of the reactants. Heated acid reacts at a faster rate and aids in the removal of acid-retarding materials such as oil, asphaltene and paraffins from the formation to give a better acid-to-formation contact. Some other benefits of heating acid are:Helps prevent precipitation of organic materials from oils that have been cooled by acids.Limits the amount of tubing contraction due to temperature Change. Problems presented by the slow reaction time of HCl in cold formations and the special problems of conducting winter time acid treatments are largely solved by heating HCl up to bottomhole temperature or more prior to pumping. This paper presents laboratory and field results to illustrate the effectiveness of the heated acid method of stimulation and compares the various methods of bringing the acid to its ideal temperature. Introduction Stimulation of formations with cold treating fluids causes a variety of problems to the oil industry.Cold treating fluids are not reactive enough, especially when the formations are themselves cool.Tubular goods will contract excessively when the formation is hot and the treating fluid is cool. Contraction can cause strain on the tubular goods and unseating of packers. Historically, in acidizing, emphasis has been on the use of retarded acids or retarded systems that place live acid deeper into the formation(1–2); however, sometimes accelerated acid systems are necessary because of cold formations or short acid pumping times. Although surfactants can aid to some degree, heating the add has been found to be the most practical means to accelerate acid reaction. Hot oilers and steam have been used to heat acid, but-their application with many acid systems was limited or they were impractical for the type of treatment to be run. A system to heat acid chemically has been developed and tested in the laboratory and field, showing excellent results. Methods of Heating Acid Chemically Heated Acid Heating acid by chemical means can be accomplished by either batch or continuous methods. The batch heating process consists of flowing ammonia into the container below the surface of the acid by means of a perforated lance. Ammonia is added until the desired temperature or acid concentration is reached. Figure 1 shows the heat derived from three different acid solutions. Large volumes of acid can also be heated simply by the continuous method. Ammonia is metered into the acid while the acid is being pumped into the well. Heat is developed rapidly and there is little heat loss on the surface because there is no exposure or delay.

The influence of the processing parameters on the performance of the two-roll piercing operation

Over the past decade, the demand for higher quality oil-country tubular goods has been increasing and to meet this demand, seamless-pipe mills have been active in developing new and improved hot-mill practices. For a hot-rolled tube on the cooling table, higher quality means more precise dimensions and improved surface quality. It is reported that pass design, piercer set-up and operating parameters have substantial influence on both dimensional and surface quality. Experimental work was conducted to determine the influence of pass/set-up design and operating parameters on the performance of first-piercing mill operation. Results showed that control of these parameters leads to an optimum pass-design that produces conditions favorable not only for enhanced deformation before fracture but also for increasing the efficiency of the mill. In this experimental work the aim was to describe the basic relationships between processing variables and their influence on the piercing performance, whilst at the same time the determination of the best overall set-up design was proposed.

Polarization Behavior of High-Alloy OCTG in CO2Environment as Affected by Chlorides and Sulfides

Pitting corrosion resistance of 13% Cr steel, duplex stainless steel, and high Ni austenitic stainless alloys for Oil Country Tubular Goods (OCTG) has been examined by electrochemical measurements in a high temperature, high pressure autoclave, simulating well conditions. Each steel shows the pitting potential in the CO2-NaCl-H2O system, the value of which becomes less noble with increased Cl− concentration and temperature. The presence of H2S is detrimental. High alloying additions of Cr and Mo enhance pitting resistance whether H2S is present or not. The corrosion potentials of these alloys in the simulated well conditions, in which oxygen is absent, do not exceed the pitting potential. Therefore, pitting corrosion can not occur by the passivity breakthrough mechanism, and may occur only when some other factor causes breakdown.

Some Factors That Affect the Sour-Service Performance of Carbon-Steel Oil-Country Tubulars

Summary Carbon-steel oil-country tubular goods, such as API 5AC Grade L-80, combine high strengths for deep-well applications with restricted hardness for resistance to sulfide stress-cracking in sour wells. Despite these general characteristics, field experience with such tubulars has not been completely trouble-free. Problems have been encountered with hardness control and testing. Metallurgical factors involved with heat treatment and upsetting have affected tubular performance. Problems associated with threaded connections and tool damage have occurred. Special considerations are required for electrical-resistance-welded (ERW) tubulars, field welding, and completion operations.

Sealing Tubular Connections

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 thetopics 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 Perhaps the most efficient method for connecting Perhaps the most efficientmethod for connecting tubes that require subsequent disconnection is helicalthreads. In fact. the Standardization Committee of the American Petroleum Inst. was formed to develop interchangeability standards for pipe connections between manufacturers. Oil Country Tubular Goods (OCTG) are intended to withstand highexternal loads, including fluids under pressure. Therefore, connections useseals that contain or exclude pressurized fluids. pressurized fluids. OCTGconnections are essentially pressure vessels that comprise threads, seals, andstop shoulders. Low design factors and external and internal clearance are theunique application criteria. Seals for these connections take two general forms-those affected by the threads and those established separate from thethreads. The tribological distinction is whether the seal is initiated by plugging the clearances manufactured between mating threads or by intimatelyfitting metal or plastic seals and seats together to form an interface. As anexample, both conditions are found in 8-Round threads, where the root/crestclearances are manufactured leak passages and the flanks are intimately fitted metal seals. Sealability Any discussion of tribological leak passages should begin with the fluid tobe sealed and the allowable leakage. "Sealability" usually refers to the ratingof a sealing system, such as the fluids that can be contained or excluded without significant leakage. "Leak-tightness" indicates the performance limitof a seal, such as "no visible water for 15 minutes," "no visible nitrogen bubbles for 3 minutes," or "10 atmospheric cubic centimeters per second (atm cm/s) helium. " Tubulars have been produced with threaded connections for more than acentury. Traditionally, a lubricant has been used to resist the gallingtendency of closely fitted, freshly machined surfaces and to seal or to plugthe leak passages. For many years thread dope for pipe threads was concocted ofan organic oil and "red" or "white" lead and sometimes graphite. As oilfieldservice grew more severe (leakage became more severe), thread lubricants changed, but their basic mission-to resist galling and to provide a seal-hasnot. Thread lubricant for rotary shouldered connections can be replenished duringtrips, but casing and tubing service exposes thread lubricants to two new elements-time at temperature and reactive fluids. Thread lubricants tend to deteriorate with temperature over time. In addition, casing and tubingconnections are expected to seal more than drilling fluids. Some of the fluidssealed are chemically reactive with the organic base of thread lubricants. Thus, threaded connections are faced with damming up the leak passages against fluids that can deteriorate the thread passages against fluids that candeteriorate the thread lubricant. API pipe threads that are expected to seal are the 8-Round (and 10-Round)and the Buttress, depicted in Fig. 1 (line pipe vee threads will not beaddressed, except to caution that they are relegated to service at less than5,000 psig [35 MPa] by API Specification 6A). The leak passages are helical capillaries that can be sealed if they are dammed at a single location alongthe passage. The 8-Round thread has two such leakage passages that are formedby the root-crest clearances. The Buttress leakage passage is a single, trapezoidal, helical passage at the stab flanks that can have about two tothree times greater cross-sectional area than both 8-Round leak passages. TheButtress thread interface can change under severe axial compression to create anew helical leakage passage at the load flanks as well (Fig. 2). Metal and plastic seals have long been used for sealing fluids, but onlysparingly on pipe connections. JPT P. 955

Critical Contents of Nickel and Chromium Required for SCC Resistance of High Alloy Oil Country Tubular Goods

Abstract Based on the laboratory SCC test results of 10 to 37% Cr, 25 to 45% Ni, 3% Mo, bal. Fe alloys, it is shown that the beneficial effect of increased Ni content on SCC resistance is retained only when the Cr content is appropriate. Good SCC resistance is obtained when the stability of austenite is above a critical value; therefore, the content of ferrite formers, e.g., Cr and Mo, should not exceed a certain limit determined by the content of austenite formers, e.g., Ni. The critical stability of austenite depends on the annealing temperature, a higher temperature requiring a higher stability of austenite.

A Test Program for the Evaluation of Oilfield Thread Protectors

Summary Transportation, handling, and corrosion damage to the threads of oilfield tubulars cost the industry millions of dollars each year. This problem has intensified with the increased use of proprietary connections, which represent a significant percentage of the total tubular cost. The thread protector is the primary means of protecting the threads from impact and corrosion damage. A test program has been designed and a test facility built. To evaluate the performance of oilfield protectors, a wide variety of thread protectors were tested, including metal, plastic, and composite (metal-elastomer) designs. This paper discusses this testing and outlines a guide for the selection of oilfield thread protectors for various service conditions. Introduction Oilfield tubular goods are exposed to a variety of hazards during transport, handling, and storage from the time they leave the steel mill until they arrive at the drilling rig site. These hazards can damage the pipe and cost the industry millions of dollars each year. Sources of these problems includetransfer between vessels (e.g., ships or trains to trucks),improper strapping of pipe during transit,handling by inspection companies, andcorrosion during storage. One way to minimize these problems is to cover the pipe ends with a good thread protector. A well-designed and constructed thread protector can provide a great amount of protection against these problems, since much of the most severe damage occurs at the pipe ends. Tubulars represent a significant percentage of an oil company's operating expenses. It is not unusual for a major oil company to spend several hundred million dollars in purchasing new casing and tubing and to spend several million dollars more to inspect those tubulars in a year's time. In almost every case, the selection of thread protectors is left to the steel mills, who attempt to follow the very brief guidelines stated in API Specs. 5A, 5AC, and 5AX. Neither API, protector manufacturers, nor steel mills have published any detailed specifications or test procedures for the selection of thread protectors. Most of the handling damage to tubulars occurs in the threads and connection seal faces. The API connections depend on thread interference for a seal, while most proprietary connections depend on a metal shoulder interference for a seal. In either case, if the critical sealing area is damaged by impact or corrosion, the connection will no longer be effective against internal or external pressure. The tubular's pin end is especially susceptible because of its exposed external threads and the lack of protective coating against corrosion (except for some proprietary connections). Zinc, tin, or phosphate coatings generally are used only on the coupling or box end. When a connection is damaged, the only recourse is to rethread the pipe. Rethreading costs for tubulars are quite high. For an API 95/8-in. [24.5-cm], N–80, 8 round (rd) long thread and coupling (LTC) set, today's cost is about $120 (but may vary on the basis of several factors). The costs to rethread proprietary connections are several times greater-often by a factor of 5 to 10. Thus, there is an even greater incentive to protect proprietary connections. To protect the pipe adequately, a well-constructed thread protector must have various attributes. It must provide adequate axial and lateral impact absorption at a wide range of temperatures (–50 to 150F [–45 to 65C]). The design and construction should cover the critical sealing areas and protect them from moisture. The protector should be vibration resistant and capable of resisting axial tension, since the protector is sometimes used to lift or drag the pipe. A good protector also should not be as hard as the pipe to prevent metal galling or seizing of the thread elements. Some other desirable features include ease of makeup or breakout, chemical resistance to cleaning solvents and sunlight, and an economical price. The price of thread protectors varies significantly depending on composition and manufacture and should be considered in relation to the cost of the tubular and the likelihood of thread damage. This paper describes the test program and generalized results of an evaluation of oilfield thread protectors. Six tests are described, including:axial and lateral impacts,vibration,thread stripping,low temperature impact,corrosion, andsolvent resistance. The purpose of each test was to simulate a real-world condition to which a protector may be subjected. Some of the tests are for relative comparisons among protectors, while other tests are based on specific criteria. Table 1 outlines the test program followed. Types of Thread Protectors In this paper, several different terms are used to identify the various thread protectors. JPT P. 306^

Completion techniques in deep geothermal drilling

The difficulties encountered during deep drilling ( > 3000 m ) in the Larderello area are caused by: • —highly fractured geological formations which prevent well completion with mud circulation, • —compact formations and, in particular, frequent variations in direction and inclination of bedding, leading to problems in achieving a vertical hole, • —high temperatures and high reservoir pressures and, • —extremely corrosive fluids in the well, and, in some cases, risk of spontaneous combustion. This paper analyses the problems arising during the first geothermal drilling and describes technological developments and experiments aimed at improving drilling techniques and materials. The most important points are: • —casing and cementation at the top of the deep reservoir, to insulate the shallow productive zone, • —control of damage and corrosion in tubular goods, • —adequate fishing techniques and/or operations to remove blockages, • —air drilling in the final phase of the well and, • —instrumentation for controlling and recording well fluid characteristics. Experiments and research on new materials are aimed at solving the serious problems caused by high temperatures and fluid composition. The risk of spontaneous combustion of fluids is also briefly described.

Completion Practices in Deep Sour Tuscaloosa Wells

Huntoon, George G., SPE, Amoco Production Co. Summary Successful development of the Tuscaloosa trend in Louisiana has required unique completion practices to produce the trend's deep sour formations. Amoco's operations in the Tuscaloosa formation are between 16,000 and 21,000 ft [4877 and 6400 m], and a range of pressure environments, high temperatures, and corrosive elements is encountered. Application of proved completion practices and equipment has resulted in several techniques that enhance the safety, longevity, and production capacity of these wells. The design of deep Tuscaloosa completions is assisted by a series of correlations developed to project bottomhole and surface shut-in tubing pressures, temperature gradients, and flow capacities for deep sour wells. This paper discusses material selection, completion practices, completion fluids, wellhead equipment, packer designs, corrosion-inhibition systems, and safety and monitoring equipment used in the Tuscaloosa trend. The design of a wellhead surface installation used to detect equipment failure, to pump kill fluids, and to circulate corrosion inhibitors is reviewed. A case study illustrates the methods used in completing a Tuscaloosa well with surface pressures exceeding 16,000 psi [110.3 MPa]. Introduction The Tuscaloosa trend extends across southern Louisiana and is approximately 20 miles [35 km] wide and 200 miles [322 km] long (Fig. 1). The formation was deposited during the Cretaceous period when Louisiana was still submerged. Sediment flowed seaward over and through a carbonate reef shelf, leaving alternating deposits of shale and sandstone. The subsequent geological history resulted in the off-shelf deposits being buried to depths of 16,000 to 21,000 ft [4875 to 6400 m]. Interest in the deep Tuscaloosa was sparked by the discovery of the False River gas field in 1975 and development continues today. The principal production is gas, with associated condensate ranging from 160 bbl/MMcf [21.3 dm3/kmol] for some wells in the Port Hudson field to as low as 2 bbl/MMcf [0.27 dm3/kmol] in a Morganza well. Drilling and completion costs have risen sharply as deeper, higher-pressure formations are penetrated, resulting in a cost averaging between $10 million and $20 million per well, depending on location and depth. Careful consideration is given to the well design to maximize production capacity, minimize corrosion, and enhance safety. Development of higher-strength, corrosion-resistant tubular goods became necessary for the deep sour-gas production in Mississippi. Operators of the deep, high-pressure Tuscaloosa wells have benefited from this technology. As a result, a rational and sound completion design for high-pressure wells can be accomplished once all the environmental factors affecting the completions are identified. There are still limitations as wells are drilled deeper and into increasingly higher pressure and temperature environments. The harsh environment of the Tuscaloosa required development of an effective inhibition program as a part of the completion design to abate potential corrosion failures. An outline of steps and procedures used in developing a completion design and methods of corrosion treatment are discussed. Special considerations necessary to complete a 21,000-ft [6400-m] well with surface pressure greater than 16,000 psi [110.3 MPa] are reviewed. Background A viable and mechanically sound completion can be designed once the environmental elements that affect a completion are understood. Since the gas composition in the Tuscaloosa contains 5 to 8% CO2 and approximately 20 ppm H2S over a wide range of pressures (8,000 to 20,000 psi [55 to 138 MPa]), specific metallurgical problems exist. Careful consideration must be given to the effects of sulfide stress cracking (SSC) and weightloss corrosion in designing tubular goods. A guide has been established in the NACE Standard MR-01-75 (1980 revision), which shows that even a low concentration of H2S at sufficient pressure will result in potential stress cracking if materials are selected improperly. The next problem is understanding the temperature and pressure environment that can be encountered across the trend. Curves were constructed from representative Amoco wells to improve prediction of temperature and pressure environments in the Tuscaloosa. The temperature profile shows that temperatures above 180F [82C] start at approximately 12,000 ft [3658 m]. Since the effects of sulfide stress cracking are negated above a threshold temperature of 180F [82C], casing strings and production tubing can be designed to optimize performance and cost. An improved method of predicting surface pressures was needed to determine the ratings required for wellheads and surface equipment. Pressures in the Tuscaloosa range from a normal gradient 0.465 psi/ft [10.5 kPa/m] in Port Hudson to abnormal 0.81 psi/ft [18.3 kPa/m] in Lockhart and Moore Sams and approximately 1.0 psi/ft [22.6 kPa/m] in certain areas. JPT P. 79^

Leak Detection — “A Necessity In Today''s Industry ”

Abstract Present methods of detecting gas leaks during testing of well heads, tubular goods, flowlines and even complete gas plants are woefully inadequate. If leaks are allowed to continue, the resulting high costs, both financial and in human life, can be disastrous. A unique method of leak detection is now being employed to record leaks as low as 0.0001 ce/sec (1 SCF in 10 years). With this innovative technology, the oil and gas industry is now able to eliminate the presence of dangerous gases to a degree not possible prior to this development. The process involves the use of a tracer gas (helium) and a portable mass spectrometer tuned to respond to the molecular weight of this gas. To date, the method has seen widespread use on production platforms in the North Sea, with outstanding success. Its reputation for providing a reliable and safe means of leak detection remains untarnished. Details of the process and up-to-date job histories will be presented in the paper. Introduction In today's petroleum industry, the demands on systems used in the transfer of hydrocarbons are rising steadily. Gas production facilities, chemical plants and oil refineries are operating more efficiently, and at higher capacities. Because these facilities deal with toxic and flammable gases at high pressures, safety standards require a high level of system integrity. This means leaks must be detected and repaired. Various methods have been used for leak detection, with limited success. Hydrostatic testing is not acceptable for establishing the leak integrity of a gas flow system due to the differences in gas and liquid flow regimes (Santeler/Moller(1)). Methane and H2S gas can closely simulate operating conditions, but the techniques and instruments used do not provide accurate and reliable results. The demand for a safer, more sensitive and quantitative method of leak detection led to the techniques described in this paper. The use of the helium mass spectrometer to detect leaks is not a novel idea-the technology has been available for over thirty years. Its use has been mainly confined to the high vacuum industry, with specialized applications in space simulation apparatus and nuclear breeder research. Initial development was tied in closely with the manufacture of mercury-are rectifiers and hermetically sealed meters for the aircraft industry. Work has progressed to include the testing of intermediate heat exchangers, as outlined by Hopkins(2) for use in liquid fast breeder facilities, but the methods used were centered around vacuum techniques. Pressurized systems, although as prone to troublesome leaks as vacuum systems, had never received the benefits of advancements in helium leak detection.

Whitney Canyon Sour Gas Well Completion Techniques

Kilstrom, Kevin J., Amoco Production Co. Summary Sour gas wells require special considerations for successful production. Corrosion, safety considerations, prolific gas rates, the casing program, and hydrate problems affect the final completion design for wells in the Whitney Canyon sour gas field. A completion technique that addresses all these constraints yet maintains a degree of simplicity and therefore presents less risk is being used in Whitney Canyon well completions. Additionally, problems that do not exist in Whitney Canyon, such as salt or sulfur deposition, can be handled with this same basic system. Introduction The economics associated with exploration of hydrocarbons in the U.S. have improved during the past 8 years, resulting in more deep drilling and frequent discovery of sour gas. One such discovery is the Whitney Canyon field located in the Overthrust Belt of southwest Wyoming, about 15 miles (24 km) north-northeast of Evanston (Fig. 1). The field was discovered in 1977 with the drilling of the Amoco/Chevron/Gulf Working Interest Unit Well No. 1, which reached a total depth of 10,691 ft (3258.6 m) in the Permian Phosphoria formation. Sour gas was recovered in the drilling fluid, and subsequent failure of tubular goods resulted in plugging back the well and completing the Triassic Thaynes formation in the 9,178- to 9,266-ft (2797.5- to 2824.3-m) interval for 4.3 MMcf/D (121.8 × 10(3) m3/d) of sweet gas and 96 B/D (15.3 m3/d) of condensate. The field is on the Absaroka thrust plate, which has resulted in placement of Ordovician Big Horn above Cretaceous rock in this vicinity (Fig. 2). The Ryckman Creek field, which produces oil and gas from the Jurassic Nugget and sweet gas from the Thaynes formation, lies 5 to 6 miles (8.0 to 9.7 km) to the east. The Carter Creek field has been shown to be a continuation of the Whitney Canyon field to the north (Fig. 3). A second well was spudded to test the deeper formations in the Whitney Canyon play and reached a total depth of 16,393 ft (4996.6 m) in the subthrust Cretaceous. Testing in this well verified substantial quantities of sour gas in the Ordovician Big Horn and Mississippian Mission Canyon carbonates and indicated sour gas in the Pennsylvanian Weber sandstone. Subsequent field development has indicated commercial quantities of gas in four of the Paleozoic Era formations. These include the Devonian Darby, Mission Canyon, Mississippian Lodgepole, and Big Horn formations. Limited quantities of sweet gas have been tested in the subthrust Cretaceous, and noncommercial sour gas production was indicated from Triassic Dinwoody and Permian Phosphoria. The approximately 4,500-ft (1372-m) thick Paleozoic interval lies at a depth range of 10,000 to 16,000 ft (4877 to 3048 m) in the Whitney Canyon area and exhibits normal pressure gradients of 0.45 to 0.50 psi/ft (3.1 to 3.4 kPa/m) and a maximum temperature of 250 degrees F (121 degrees C). Drilling has taken place for 13 miles (21 km) along the Whitney Canyon/Carter Creek trend, indicating a sizeable productive area (Fig. 3). The reserves of sour gas are trapped in the folding associated with the thrust faulting in the area and are held in primary and secondary porosity (matrix porosity in the 5 to 10% range). Permeability is generally low [matrix permeability less than 0.1 md (9.869 × 10(-5) mum2)] and production is highly dependent on extensive natural fracturing. The gas composition in the Whitney Canyon field varies from formation to formation, with all of the Paleozoics indicating H2S content from 1 to 15 mol%. The Mississippian Age Mission Canyon formation has indicated the largest reserves in the field and one 30-ft (9.1-m) interval in the Champlin 457 A Amoco No. 1 well tested at 33 MMcf/D (934.5 × 10(3) m3/d) (Table 1). The Mission Canyon formation is a 1,000-ft (304.8-m) thick carbonate section with a gas composition of approximately 15% H2S, 5% CO2, and 70% methane, and the balance is ethane and heavier hydrocarbons. To develop a successful completion design for the Whitney Canyon field, we first defined all factors that would be detrimental to production. JPT P. 40^

Fracturing Fluids for Deep, Hot Formations

Summary Cross-linked gels are adequately stable at high fluid temperatures and, thus, have established their usefulness for fracturing high-temperature formations. However, in certain treatment situations, they may develop high friction pressure in tubular goods, which can limit their injection rate. Furthermore, the rheological properties exhibit a timeshear history dependency that is difficult to predict. Two-stage gel systems have been very successful in providing a means to develop desired viscosity at providing a means to develop desired viscosity at downhole conditions without causing high tubular friction pressures. However, several currently available systems do not have the stability required for large volume treatments at temperatures above 250 degrees F (120 degrees C). A fracturing fluid has been developed that solves many disadvantages and limitations of both crosslinked and two-stage gel systems. This is made possible by the use of a new delayed hydrating gelling possible by the use of a new delayed hydrating gelling agent. The fluid has the desired two-stage viscosity qualities and can be formulated to provide the desired viscosity throughout a treatment. In addition, the rheological properties of the new fluid system are highly predictable. This fracturing fluid system has been tested successfully in the field. Fluid design and treatment results are presented. Introduction The commercial success of massive hydraulic fracturing (MHF) in tight gas reservoirs has been well documented. For example, successful stimulation programs have been used to produce wells in the programs have been used to produce wells in the Cotton Valley Lime, Cotton Valley Sand, Edwards Lime, J Sand, and Mesa Verde Sand formations. Recent renewed efforts to develop deep formations with temperatures exceeding 250 degrees F (121 degrees C) - such as the Silcos Sand, Grey Sand, Shannon Sand, and deep Cotton Valley Lime - have required that more stable fracturing gels be developed to place large quantities of proppant successfully. This is especially true for placing the higher density bauxite proppant required for most of these deep formations, where closure pressures could exceed 12,000 psi (82 MPa). Typical job volumes in these formations range from 80,000 to 800,000 gal (303 to 3030 m3) of gelled fluids with pumping time ranging from 3 to 14 hours. Most fracturing fluid systems available for stimulation under these temperature and pumping- time conditions are based on the use of various pumping- time conditions are based on the use of various derivatized guar polymers as the basic viscosifying agents. The temperature stabilities of these polymers are functions of fluid pH, ionic strength, and the presence of added stabilizers. Many of the available presence of added stabilizers. Many of the available fluid systems also are cross-linked with one of a variety of metal cross-linking agents. In general, the ability to stabilize the base polymer will dictate the time/temperature stability of the system. Furthermore, the upper temperature limit for cross-linked systems may be less than that of the base polymer with the appropriate stabilizers and delayed hydrating polymer. During recent efforts to improve MHF design, the critical role of viscosity control has been defined. Fluids with too little viscosity may suffer from excessive fluid loss, short propped length, narrow width, and premature proppant deposition. Fluids with too-high viscosity may create excessive fracture widths that can reduce the propped fracture length and cause high fracture friction pressure, which may result in premature job termination. Since each fluid increment experiences different fluid- temperature profiles, careful control of fracture viscosity requires the use of multiple fluid formulations. Derivatized guar fluids can be used for treatments up to 250 degrees F (121 degrees C) without added stabilizers. The use of methanol and other stabilizers has extended the fluid stability to 350 degrees F (177 degrees C). JPT P. 2213