bluuebunny/crossref_metadata_2025_split huggingface dataset:
Corrosion Behavior of Various 13 Chromium Tubulars in Acid Stimulation Fluids
Authors: Ke Mingjie , Boles Joel 
Published: December 2007

Abstract
The oil industry has used 13 Chromium (13Cr) materials in oil and gas wells for many years. As wells are drilled deeper, the production environments become more aggressive, primarily due to high-temperature and high-pressure conditions, and sweet/sour gas production. These conditions present a challenge to tubular products. To meet industry demands, the tubular manufacturers have developed various chemically enhanced 13Cr materials for these applications. These tubular materials also challenge the corrosion inhibitor technology applied in acid stimulation fluids. There are many publications related to acidizing wells completed with 13Cr tubulars; however, regarding corrosion behavior of enhanced 13Cr materials in stimulation fluids, very little information has been published.
This paper presents results of acid corrosion tests performed on various 13Cr samples from two manufacturers at temperatures from 180°F to 312°F (82-156ºC) and from 6 to 30 hours of exposure. In addition, the acids were varied from acetic acid and hydrochloric acid to systems with hydrofluoric acid. The 13Cr samples ranged in yield strength from 85 to 110 ksi. Results indicate that corrosion behavior of enhanced 13Cr in acids can be completely different from that of 13Cr depending on an inhibitor package applied, and that strength of the material plays a significant role in corrosion behavior. Also, the data shows that some inhibitor packages typically used for 13Cr do not provide adequate corrosion protection on enhanced 13Cr materials.
Biocide Stimulation in Oilwells for Downhole Corrosion Control and Increasing Production
Authors: Rincón Pedro R. , McKee John P. , Tarazón Carola E. , Guevara Luis A. 
Published: December 2007

Abstract
Sub-surface corrosion related to sulfate reducing bacteria has been noted in some of the oil-wells in Eastern Venezuela. Production is by electro-submersible pump (ESP), mechanical pumping or gas lift, from horizontal or standard gravel-packed completions. These wells have experienced an increase in water cut, coupled with increased corrosion rates. The corrosion is mainly associated with bacterial activity. The original purpose of the Tetrakishydroxymethylphosphonium sulfate (THPS) treatment was to reduce the corrosion levels associated with the bacterial activity, predominantly sulfate reducing bacteria (SRB). The squeeze type treatments incorporated THPS along with a non-ionic surfactant. These treatments have been successful in reducing corrosion levels and hydrogen sulfide (H2S) in the gas phase. In many cases, H2S levels have been reduced from, e.g. 330 ppm to 20 ppm. The corrosion rate in surface coupons, in some cases, has been reduced from, e.g. 70 mpy to 0.6 mpy. Well head coupons, employed to monitor corrosion rates, were also used to determine the amount of iron sulfide deposited on the coupon. A novel field evaluation method, discussed in this paper, was used to quantify the amount of iron sulfide deposited on the coupon, and thereby infer the bacterial activity and iron sulfide deposition in the completion.
An added benefit of the THPS squeezes, that was not anticipated, was the increase in oil production in several of the wells treated. These increases in oil production have ranged from 20% to more than 300 %.
This study will discuss the criteria used to select the candidate wells, the methodology employed in the application of the THPS, and corrosion rate and production rates obtained.
Application of pH Buffer as Corrosion Inhibitor in NaBr Brine Packer Fluids at High Temperatures
Authors: Ke Mingjie , Javora Paul H. , Qu Qi 
Published: December 2007

Abstract
Sodium bromide brine (NaBr) has been widely used as a packer fluid in well completions for more than 20 years. While NaBr brines exhibit low corrosion even at high temperatures, some oilfield tubular materials are susceptible to pitting and localized corrosion. Traditionally, film-forming amine and low molecular weight inorganic sulfur (SCN-) chemicals have been added as corrosion inhibitors. However, when applied at high temperature, thermal decomposition has become a critical issue. Furthermore, adverse effects on tubular materials, downhole elastomers and formation rock have been documented. Alternatively, corrosion may be controlled by increasing the pH of the brines. While pH can be raised by the addition of sodium hydroxide (NaOH), lime (CaO), hydrated lime (Ca(OH)2), and the magnesium analogues, these chemicals provide less control and less protection for tubular materials, especially when the influx of an acid gas is possible.
This paper describes laboratory results of a pH buffer applied as a corrosion inhibitor in NaBr brines and field case histories for buffered NaBr packer fluids in high-temperature high-pressure wells. Results from buffer capacity, general corrosion, galvanic corrosion, and stress corrosion cracking (SCC) tests are presented. Field case histories are presented to demonstrate the successful use of the pH buffer in NaBr brines.
Chemical Optimisation Case Histories and Cost Benefits
Authors: Coupe P. J. , Breakey E. 
Published: December 2007

Abstract
The development of high resolution metal loss techniques has opened up the possibility of real time monitoring in applications that had previously been notoriously difficult to investigate, such as subsea or multiphase systems. The main impact of these developments has been on improvements in the application, evaluation and optimisation of corrosion inhibitors.
The following paper presents a number of case histories that illustrate the design and operating cost benefits that can be achieved through application of high resolution real time corrosion monitoring.
Electrochemical Techniques for Corrosion Assessment in Oil Production Systems
Authors: Caldora Federico Cesar , Rossi Juan Pedro , Pellicano Adolfo 
Published: December 2007

Abstract
As a primary issue of its integrity and corrosion control program, Pan American Energy implemented on 2003 a corrosion monitoring program for both external and internal corrosion, for oil production and water injection systems, based on electrochemical techniques 1. For this purpose, 200 electrochemical sensors were installed in the most critical sectors of Cerro Dragón oilfield, with capability for both DC and AC electrochemical measurements, including Polarization Resistance (PR), Electrochemical Impedance Spectroscopy (EIS), ON-OFF potential depolarization curves and cathodic protection current.
This work is entirely based on field measurements and describes observations and results obtained in the last year, regarding early detection of critical corrosion cases, corrosion mechanisms identification and assessment of corrosion mitigation systems efficiency (external and internal).
As a result of the new monitoring program, the following relevant results were so far obtained: Three oil treatment plants were identified as high-risk systems from the corrosion standpoint.Cathodic protection inadequacies were detected in more than 50 % of the instrumented systems.Inefficiency in chemical treatment dosage for internal corrosion control was established in at least 17 % of the instrumented systems.
These outcomes are based primarily on PR and EIS measurements, being the latest one of the first field applications in oil and gas industry. They also allow to conclude that the application of advance electrochemical techniques to corrosion monitoring of oilfields facilities, provides a powerful tool for instantaneous detection of changes in corrosion behavior and trends, due to variations in operating conditions, fluid aggressiveness and corrosion mitigation parameters. The use of this methodology applies to corrosion monitoring of pipelines, tanks and surface facilities, and provides a direct contribution to technical knowledge in corrosion mechanisms identification, corrosion mitigation efficiency assessment, corrosion trend prediction and actual correlation between corrosion and operating variables.
Workovers in Sour Environments: How Do We Avoid Coiled Tubing Failures?
Authors: Nasr-El-Din Hisham A. , Metcalf Arthur S. 
Published: December 2007

Abstract
Workovers of sour wells (H2S contaminated) including gas, oil and water injection wells, present special challenges. Fields in Russia, Canada and Saudi Arabia are some of the most significantly affected. Add higher temperatures and specialty equipment and sometimes failures can result. Coiled tubing has become one of the mainstays in treating these types of wells. Failures can be such that the tubing is recovered completely with leaks while catastrophic parting of the coiled tubing can leave several thousand feet including bottomhole assemblies to be fished.
Corrosion protection to the proper level of weight loss (&lt; 0.02 to 0.05 lb/ft2) and zero localized surface defects (pitting and stress cracking) both in live and spent acid solutions is essential to protecting the production equipment. Doing this is a step towards avoiding coiled tubing failures during acid treatments down coiled tubing. However, more than this is essential to the safe usage of coiled tubing. Included in this is proper selection of metallurgy for the downhole environment, appropriate use of hydrogen sulfide inhibitors, non-destructive testing of the coil prior to usage, periodic sampling of the coil for physical examination and more are still in the development stages.
This paper reviews two case histories of coiled tubing failures during workovers, including the analyses that were performed and recommendations defined of practices to avoid reoccurrence. Further, a suggested set of guidelines are presented for the safe usage of coiled tubing for workovers in sour wells.
Open-Hole Horizontal Drilling and Gravel-Packing With Oil-Based Fluids - An Industry Milestone
Authors: Wagner M. , Webb T. , Maharaj M. , Twynam A. , Green T. , Salamat G. , Parlar M. 
Published: December 2007

Abstract
An increasing number of horizontal wells requiring sand control are being gravel packed, particularly in deep-water and/or sub-sea environments, where completion reliability is paramount due to prohibitively high cost of remediation. Tophole sections in many of these wells are being drilled with oilbased fluids, with the common practice of switching to waterbased fluids when the reservoir drilling starts. In the last several years, some operators started using oil-based drilling fluids in the reservoir section as well, and gravel packed them with water-based fluids. In some cases, these practices required running pre-drilled liners in oil-based fluids, and subsequently displacing to water-based fluids, prior to running in hole with the sand-face screens and gravel packing. In other instances, screens could be run in hole with oil-based fluids in the wellbore, and gravel packing could be performed with water-based fluids. In both cases, the presence of reactive shales and/or water-sensitive productive zone can introduce serious concern in the event that the carrier fluid losses occur into the formation during gravel packing. Although a base-oil or diesel can be used as a carrier fluid, low density of the base oil limits such applications to low-pressure/depleted wells.
In this paper, we present a case history of the first successful application of drilling and completing in an all oil environment, utilizing a reversible oil-based reservoir drilling fluid and an oil-based gravel packing fluid. The carrier fluid used in this application included a filtercake cleanup solution in the aqueous internal phase of the oil-based carrier fluid, extending the application of simultaneous gravel packing and cake cleanup processes that have been successfully practiced in water-based fluid environments, to oil-based systems. The subject application was in a high-rate gas field located offshore Trinidad, with anticipated production rates in excess of 150 MMSCFD per well. Presented in the paper is the drilling and completion selection methodology based on extensive laboratory and yard testing, along with the details of the completion and recommendations for future applications based on lessons learned. A direct comparison of the all-oil drilling and completion process to water-based drilling and completion is also presented based on a case history from the same field.
A Fuzzy Expert System for the Completion of Multilateral Wells
Authors: Garrouch Ali A. , Lababidi Haitham M. S. , Abdullah S. Ebrahim 
Published: December 2007

Abstract
This study presents the development of a web-based fuzzy expert system for aiding in the planning and completion of multilateral wells. The reasoning process is based on a systematic planning approach for screening and selecting multilateral well candidates, lateral-section completion types, and the junction levels of complexity. A modular approach was employed. The system has been fully implemented to run on the web and provides an excellent example of how a number of heterogeneous tools and applications can be integrated on the web. Rule-based knowledge sources and the inference mechanisms were implemented using Resolver.
The recent evolution of multilateral technology introduced a large variation of completion options for multilateral wells. Many of these options are simple and basic while others are complex. These complex completions allow the use of multilaterals in a much wider range of well scenarios that can accommodate a large number of production-styles constraints and rock-properties conditions. The development of a fuzzy expert system, that implements a comprehensive planning approach for multilateral well completion, allows to deal with ambiguous well-completion scenarios. It also introduces a systematic approach for the design of fit-for-purpose multilateral wells with intelligent flow capabilities.
Using Mature Upgraded Drilling Equipment to Successfully Drill Variably Pressured Indonesian Gas Wells
Authors: Hudson Jerry , Buhron Heriadi , Wright Hoover 
Published: December 2007

Abstract
The Sanga Sanga Production Sharing Concession, Eastern Kalimantan, Indonesia, includes the Badak, Nilam, Semberah, and Mutiara fields. Successful continuing development of these fields poses logistical, drilling, and geologic challenges that vary from field to field. This paper discusses these challenges, here treated in the order in which they are typically encountered in practice. These challenges include:Dealing with complex geology including a variety of structural closures as well as erratically distributed ancient river sands that occur as stacked pays in different combinations from well to adjacent well. Developing designer wells to exploit stranded attic gasCoping with hard-to-access terrain that ranges from hilly topography to low tidal areasEnvironmental issues: protection, waste handling, bioremediationDealing with varied land drilling rig configurations and different crews to man themMaintaining equipment in good working orderDrilling — with above normal mud weights to maintain borehole stability with wide variations in differential pressure — through shallow, higher pressure, gas-bearing sands into significantly lower pore pressure gas-bearing sands at depth
VICO Indonesia currently operates the Sanga Sanga Production Sharing Concession. This project, a joint venture between BP and ENI, has been on production since the early 70’s. These fields feed gas to the Bontang LNG plant; the world’s largest LNG facility, and it is a significant, major challenge to drill wells in a timely and efficient basis to maintain supplies to Bontang plant.
This paper will review the steps taken to deal with the various individual challenges in multi-field development. The more difficult challenges are interpreting the geology, designing special purpose wells, and. drilling through sections with variable pore pressures.
New Techniques Improve Well Planning and Survey Calculation for Rotary-Steerable Drilling
Authors: Liu Xiushan , Liu Rushan , Sun Mingxin 
Published: December 2007

Abstract
Rotary-steerable technology is progressing rapidly all over the world because of the improvements in hole cleaning and torque-and-drag. It works well especially in extended-reach drilling and holds great promise in directional work.
In rotary-steerable drilling operations, bit walk objectively exists along an actual drilled well trajectory. The drilling experience shows that it is an effective measure to control a well trajectory by use of the physical bit walk. The authors developed a method to plan various bit-walk paths with any combination of arc and straight sections in the vertical expansion plot.
The authors also presented a method to calculate a drilled well bore trajectory directly using the rates of inclination change and azimuth change for rotary-steerable drilling. Compared with the radius of curvature method and minimum curvature method, the most commonly used methods in the oil field, the improved method of survey calculation yields more accurate and stable results.
When a well trajectory deviates from the planned path, the driller must make a path correction and the correcting section has to employ a 3D trajectory to hit the predetermined target. Existing methods for planning 3D trajectories are available, but their objectives are only to hit the expected targets. In some cases, however, adjusting the trajectory to the preferred direction is more important than only reaching the target. For example, when drilling horizontal wells, engineers must focus on trajectory direction to land the build-up section successfully and continue drilling the horizontal lateral. The authors proposed a method to make a soft landing of well path, which yields a well trajectory that reaches the expected target from a specified path direction, with no need for trial- and-error procedures.
In a word, the methods in this paper represent significant improvements over the traditional well-path planning and survey calculation techniques, and were programmed into computer software. The results proved satisfactory for directional and horizontal wells in China.
Efficient System for Hands-Off Makeup of New Drillstrings for Extended-Reach, Deep, and Highly Deviated Wells
Authors: Abrahamsen Egill 
Published: December 2007

Abstract
The typical iron roughneck (a machine for making up and breaking out drillpipe) was designed for conventional API rotary-shouldered connections long before today’s demanding well profiles, when a typical torque wrench rotation of 25 to 30° was sufficient for making up these standard drillstring connections after initial spin-in.
New drillstring connections, such as HT, XT, XT-M, DSTJ, GPDS, Omsco TM2, and WT, were designed to withstand the increased loads and bending forces experienced in highly deviated and extended-reach wells. Some of these connections also provide improved flow characteristics to better bring drill cuttings to surface in extended or slim well designs. A common operational factor for many of these connections is the early build-up of torque during spin-in, which demands extended wrenching rotation by the makeup tool (wrench) after spin-in to reach final makeup torque. Traditional iron roughnecks must, therefore, frequently do more than one wrenching cycle (up to five cycles with WT) to make up or break out many of these connections, reducing the tripping efficiency when hole conditions require the use of these drillstrings.
This paper describes the concepts of a new-generation tool that was developed to efficiently address the modern make/break requirements presented by the new drillpipe connections. Making up or breaking out these connections in a single stroke, using a patented rotational torque wrench and spinner combination, this tool offers a wrenching rotation of 140° at torque values up to 145,000 ft-lb.
As an added tong module to an existing modular tong carrier/tong positioning system, the tool also handles a variety of tongs for casing, tubing, production risers, and drillstrings. With integrated remotely controlled features like a mud bucket, a stabbing guide, and a cleaning and doping device, the tool and accessories form an efficient system for hands-off makeup of new drillstrings for extended-reach, deep, and highly deviated wells. This system can also be viewed as a multifunctional iron roughneck that handles not only drillstring connections but also all types of tubular goods.
Slim Riser - A Cost-Effective Tool for Ultra Deepwater Drilling
Authors: Childers Mark , Quintero Alan 
Published: December 2007

Abstract
Until recently, operators have often been faced with a stark choice when planning their deep and ultra deep (over 5,000 ft) water drilling programs. They either paid the high cost of major Mobile Offshore Drilling Unit (MODU) upgrades or the high day rates associated with new, 5th Generation MODUs. Recently, the Surface BOP (SBOP) Concept appeared as an alternative with attractive advantages under certain circumstances. A third alternative is herein presented. Namely, the Slim Riser Concept that can be used to bring older 3rd and 4th Generation rigs into the deepwater arena on a favorable economic basis, but still maintain many of the advantages of the standard, Conventional 21-inch riser, 18-3/4 inch BOP subsea system.
The key features of the slim riser concept presented are:16 inch riser, which substitutes the Conventional 21 inch riser.The rig retains its existing 18 ¾ inch BOP stack and lower riser assemblies (LMRP) such as the flex joint.The rig retains its 21 inch upper riser assemblies such as the diverter, telescoping joint, etc.Several options, including a preinstalled wellhead sleeve in a conventional 18 ¾ inch housing, can be chosen to reduce the effective wellhead bore.
By reducing the riser size from 21 inch to 16 inch OD a rig’s water depth capability is improved significantly due to:Reduced tensioner loadsLower variable deck loads (VDL) requirements due to weight savings from the reduced volume of stored mud and reduced riser tensionsReduced required mud pit space due to the smaller riser volumeReduced riser storage requirements due to the smaller riser
This paper will fully explain the Slim Riser Concept including:A comparison to Conventional 21 inch riser systems and SBOP systemsA review of the 16 inch riser designBOP control system considerationsExploration of casing program considerations with slim hole drillingExploration of slim hole wellhead systems with standard 18-3/4 inch housingsExploration of mooring system considerations, including the use of conventional spread moored or taut/semi-taut line systemsExploration of guide line versus guideline-less reentry with Slim RiserField installation considerations
In addition, the paper will compare the tools available for ultra deepwater drilling including Conventional 21-inch riser drilling, drilling with SBOP and drilling with the slim riser concept. Guidelines will be presented for selecting the "right" system for the "right" application.