bluuebunny/crossref_metadata_2025 huggingface dataset:
Surge Pressures in Low-Clearance Liners
Authors: Mitchell Robert F.
Published: December 2007

Pressure surges have long been known to cause well-control problems. As early as 1934, pressure surges resulting from pipe swabbing were identified as a possible cause of fluid influx, and in extreme cases, blowouts, and lost-circulation problems.

In most wells, the magnitude of the pressure surges is not critical became proper casing design and mud programs leave large enough margins between fracture pressures and formation-fluid pressures. A certain fraction of wells, however, cannot be designed with large surge-pressure margins, and some operations are particularly prone to large pressure surges, in particular, the running of low-clearance liners in deep wells.

Low clearance liners have several characteristics not present in the usual surge/swab situation. First, the low clearance produces large fluid friction effects, slowing the liner's speed relative to the surface speed. The moving liner "scrubs" fluid from the wellbore wall, producing lower than expected pressures and allowing fluid influx from the formation. Because fluid ahead of the liner cannot easily penetrate the low clearance annulus, fluid swabbing occurs behind the liner, while larger than normal surge pressures are produced ahead of the liner.

Typically, pressure surges in critical wells are estimated by "steady-flow" fluid models. These models consider the complexities of the non-Newtonian flow of drilling muds, but usually neglect fluid inertia and the compressibility of the fluid and wellbore. The lack of fluid compressibility is considered a conservative assumption because it overpredicts flow rate, while the neglect of fluid inertia is not considered a conservative assumption, because pressure is needed to accelerate the mud when the pipe is run.

Calculating dynamic surges with high fluid friction also presents technical difficulties. Because the fluid flow is overdamped, care must be taken to avoid unstable behavior of the fluid system. Pipe elasticity also needs to be considered, because of the high axial forces developed by the fluid friction at the liner.

This paper fully describes the technical details for calculating dynamic surge pressures with high viscous forces in the low clearance liner annulus. Several sample problems of realistic low clearance liner runs are used to show the unusual pressure distributions developed by these cases. The potential problems running low clearance liners are examined, and possible solutions are presented.
2,000,000 lb. Landing String Developments: Novel Slipless Technology Extends the Deepwater Operating Envelope
Authors: Simpson Burnie , Payne Michael L. , Jellison Michael J. , Adams Burt A.
Published: December 2007

This paper pertains to the technological development of a completely integrated landing system that provides the ability to extend the deepwater drilling and completion envelope. This system is comprised of an elevator, slipless spider, and landing string all specifically designed to land heavy casing strings in deepwater wells thus overcoming the load limitations of conventional equipment. All stages of evolution are analyzed including research, development, design, verification testing, manufacturing, proof testing, running, handling, and actual case histories detailing field use. Actual verification testing loads were over 5,200,000 lbs and proof testing loads were 3,000,000 lbs. Unique manufacturing challenges and solutions associated with the production of ultra-thick wall landing strings with 2,000,000 lbs super premium yield ratings1 (90% remaining body wall) are presented in detail.
Foam Cement Engineering and Implementation for Cement Sheath Integrity at High Temperature and High Pressure
Authors: Griffith James E. , Lende Gunnar , Ravi Kris , Saasen Arild , Nødland Nils Egil , Jordal Ole Henrik
Published: December 2007

Cementing high-pressure, high-temperature (HPHT) wells poses various challenges not seen at normal well conditions. For instance, the following objectives are critical for HPHT wells:

Prevent losses during drilling fluid circulation and cement slurry placement. Displace the drilling fluid and place the cement slurry effectively. Prevent free-water or gas-channel development. Reduce slurry fluid loss. Provide support for the production packers. Decrease compression loads on casing connectors. Prevent damage to cement sheath. Prevent annular gas pressure over the life of the well.

The industry is recognizing the interaction between these factors to determine the optimal cement job design for accomplishing these objectives. This paper presents and discusses the engineering analysis to determine the optimum foamed cement sheath properties for integrity during the life of the well at HPHT conditions. Also, this paper compares foamed cement to nonfoamed slurries in achieving these objectives. Other important issues discussed are the performance of nitrogen at HPHT conditions and the rheological properties of the foams. Key issues addressed are the state and solubility of nitrogen under downhole conditions and the integrity of the cement sheath during the life of the well. Thermodynamic solution theory and experimental studies are applied to the former, and finite element analysis is applied to the later.

Case examples are presented discussing foamed and conventional operations at near HPHT conditions for some Norwegian, North Sea wells. Cement properties are contrasted for the different foamed and conventional cement slurry properties with respect to:

Achieving the HPHT objectives, such as placement efficiency and sheath properties Prejob design to obtain the objectives Job planning and procedures Job execution Logging of foamed cement Post-job evaluation of the cement systems
New Expandable Cladding Technique Enables Extended Length Casing Repair
Authors: Jabs Matthew , Harmon Charles E. , Harmon Steve C. , Harmon Robert E.
Published: December 2007

In June 2003 a project in south central Oklahoma incorporated the first use of an expandable metal casing patch technology to repair a damaged well bore casing section. The cladding was deployed to correct a casing collapse problem that occurred when an offset injector well went online and caused the existing casing to fail. The well has been an oil producer and was originally drilled in the early 1950s. This technology provides the operator with the ability to create a definitive casing repair with pressure integrity and minimal well restriction.
Drilling Salt Formations Offshore With Sea Water Can Significantly Reduce Well Costs
Authors: Willson Stephen M. , Driscoll Pete , Judzis Arnis , Black Alan , Martin Wes , Ehgartner Brian , Hinkebein Tom
Published: December 2007

Rate of penetration (ROP) increases significantly if salt formations are drilled using undersaturated fluids. This is especially true when drilling riserless. Of primary concern is the amount of hole enlargement that will occur. However, if managed, then a step-change in drilling performance and costs can be achieved.

This paper presents, in detail, the results of a comprehensive and large-scale laboratory testing program performed on outcrop salt samples that replicate drilling salt formations with undersaturated drilling fluids with flow rates of up to 1000 gpm. The laboratory-testing program includes tests performed in a CT-scanner to map hole enlargement in real-time, as well as variously sized borehole leaching tests with borehole diameters of up to 6". Flow rates are scaled to produce comparable levels of turbulence occurring in the field.

An analytical hole enlargement prediction model is presented that incorporates the effects of ROP, pump rate, drill-fluid saturation, dissolving salt drill-cuttings and salt leaching from the borehole wall. This model accurately predicts, to within 10%, the measured hole enlargements produced in the scaled laboratory tests, for a wide range of flow rates and fluid saturations.

Predictions of field performance are made, and the implications of the predicted hole geometry discussed. Provided high rates of penetration are realized, acceptable hole geometries will result, even when pumping seawater at flow rates of up to 1600 gpm. A field application is described, whereby the historical practice of drilling the last 200 ft of the 20" hole into salt using a saturated brine drilling fluid was discontinued in preference to continued use of seawater. The competing influences of increasing rate of penetration and avoiding the cost of a sacrificial mud system, offset by the increased cost of cement, resulted in cost savings of $250,000 per well. Implemented in a multi-well sub-salt development, cost savings of over $1.5 million will be realized in the drilling program. Further applications of this technology are now being sought.
Bounds on In-Situ Stress Magnitudes Improve Wellbore Stability Analyses
Authors: Aadnoy Bernt S. , Hansen Ann K.
Published: December 2007

Wellbore stability analysis is becoming a necessary tool to improve operational economy and to avoid wellbore problems. Essential elements here are estimation of critical fracturing and collapse pressures to obtain an optimal mud weight window.

The input data for this analysis is mainly pore pressure predictions from many sources like logs and drilling exponents, overburden stresses from logs or drilled cuttings, leak-off tests at casing shoes and breakout analysis from caliper logs. From these and other data, estimates for in-situ stresses and directions are obtained, which again serves as input for wellbore stability modeling. It is evident that the input data comes from many different sources and can therefore not be considered consistent.

During wellbore stability modeling it has often been observed that unrealistic results appear. Sometimes one observes a critical collapse pressure that exceeds the fracturing pressure, clearly a faulty result. These results are often ignored. However, there must be an inherent error in some of the input data. This paper addresses this problem and concludes that the relative magnitudes of the in-situ stresses are the main cause of this. Equations are given that defines the bounds on the in-situ stresses for different stress regimes.

Using the bounds on the horizontal in-situ stresses on field cases, realistic fracturing and collapse prognosis are always obtained. Since the models also define the minimum permissible anisotropic stress state, these can be used as default parameters when field data are missing.

A field case from the North Sea demonstrates the application of the stress bounds, and shows that prognosis are obtained that better corresponds to observed behavior of the wells.
Improved Bottomhole Pressure Control for Underbalanced Drilling Operations
Authors: Pérez-Téllez C. , Smith J. R. , Edwards J. K.
Published: December 2007

Maintaining underbalanced conditions from the beginning to the end of the drilling process is necessary to guarantee that underbalanced drilling (UBD) operations successfully avoid formation damage and potential hazardous drilling problems such as lost circulation and differential sticking. However, maintaining these conditions during operations with jointed-pipe is an unmet challenge that continues motivating not only research but also technological developments.

This paper proposes an improved UBD flow control procedure as an economical method for maintaining continuous underbalanced conditions in jointed-pipe UBD operations by maximizing the use of natural energy available from the reservoir through the proper manipulation of nitrogen and drilling fluid injection flow rates and choke pressure. It is applicable to wells that can flow without artificial lift and within appropriate safety limits.

The flow control procedure is based on the results of a new comprehensive, mechanistic steady-state model, validated with both field data and full-scale experimental data, and on the results of a simplified, time dependent, mechanistic model, which numerically combines the accurate mechanistic, steady-state model, the conservation equations approximated by finite difference, and a well deliverability model.
Thermal Modeling of Shut-In Well After Multiphase Hydrocarbon Production
Authors: Shah P. C.
Published: December 2007

When a well that has been producing a mixture of oil, water and gas is shut-in for an extended period of time, the fluid columns expand or contract in response to the temperature changes in the well. These changes in fluid levels in turn, affect the heat transfer in and around the wellbore. This coupled problem of determining the fluid levels as well as the wellbore temperature distribution is addressed. An algorithm is proposed, implemented and discussed for a hydrocarbon that can be modeled as a black-oil. Special cases of the algorithm when one of the phases is absent are also included.

This model helps accurate and rigorous prediction of the wellbore temperature distribution and the wellhead pressure during a shut-in. Accurate temperature and pressure estimates in turn lead to better stress calculations to ensure the design of the wellbore with improved integrity of the tubulars.
Field Experiences Using ‘Oil Soluble’ Non-Aqueous Scale Inhibitor Delivery Systems
Authors: Miles A. F. , Vikane O. , Healey D. S. , Collins I. R. , Saeten J. , Bourne H. M. , Smith R. G.
Published: December 2007

‘Oil Soluble’ scale inhibitor delivery systems are believed to have been first applied to an onshore well in Colombia in 1997. Products of a similar type have since been used in a number of applications including wells in the UK and Norwegian Sectors of the North Sea and in North America.

In addition to oil soluble products, other technologies designed to avoid the problems sometimes observed with aqueous treatments have also been developed and deployed in similar, challenging, environments. The different technologies are now commonly referred to as non-aqueous systems to distinguish them from more traditional, aqueous methods.

This paper will review each of the non-aqueous technologies currently available followed by a detailed description of field experiences, both good and bad, found by BP, ChevronTexaco, Statoil and other operators using oil soluble systems. Where problems were encountered, the laboratory work to investigate these difficulties will be described and the main findings presented. Recent advances using the knowledge gained from the investigation of earlier challenges will also be presented.
An Unconventional Scale from an Unconventional Reservoir
Authors: Sitz Curtis , Shumway Jacob , Miller Cindy
Published: December 2007

As gas fields are developed around the world, new and interesting scale challenges are presented. In the United States, gas reserves are found in fields near Green River, Wyoming. This gas is produced from shale layers interbedded with the carbonate mineral trona, or, sodium sesquicarbonate, Na3H(CO3)2*2H2O. Well known carbonate minerals, such as calcite, siderite, and dolomite are relatively insoluble in water, and are often found in the rock matrix of hydrocarbon reservoirs. Unlike these conventional minerals, trona is extremely water soluble at reservoir conditions. Under normal circumstances, if left untreated, the production of the mineral saturated brine leads to significant deposition of scale in the production tubing and surface facilities.

Two major challenges are presented with trona scale deposition.

The first challenge is in the prevention of the mineral deposits. Like conventional carbonate scales, inhibition is possible with chemical inhibitor treatment. There are also non-typical treatment options, both chemical and thermodynamic, that were investigated and evaluated for effectiveness.

The second challenge is in the removal of deposited scale. It is common to remove carbonate scales by the application of an acid, but the trona scale is an unusual exception. The addition of an acid actually encourages deposition since the composition and solubility of this mineral scale are very sensitive to changes in pH.

This paper discusses the laboratory work performed that led to an understanding of the problem and to the proposal of rather unconventional procedures necessary to prevent the scale and to eliminate the existing deposits.
The Challenge of Squeezing a Water Sensitive HP/HT Reservoir - Lab and Field Experiences with a Novel Non Aqueous Inhibitor/Squeeze Enhancer Package
Authors: Chen Ping , Hagen Thomas , Bourne Hugh , Turner Katherine , Nielsen Frank Møller , Rian Mette , Haldoupis Andreas
Published: December 2007

Down-hole scale control in Statoil's Åsgard field presents a particularly severe challenge. The field is producing from low permeability formations with a high draw down, through subsea templates. System pressure and temperature changes experienced during production promote the formation of carbonate scales, which have been identified in the near well bore area and perforated intervals. The high formation temperature and pressure, 165°C and 500 bars respectively, high chlorite content coupled to the water sensitive nature of some of the formations creates a challenging environment for downhole scale treatments.

This paper will describe possible formation damage mechanisms that were identified for this water sensitive formation and the treatment strategy adopted to minimize them. It also presents the extensive laboratory studies that were undertaken to develop a non-damaging, non-aqueous inhibitor/squeeze enhancer formulation suitable for deployment under these harsh conditions. An understanding of the mechanisms by which the squeeze treatment package prevented water block formation and clay mobilization under such severe temperature and reservoir constraints, coupled to the mechanisms of squeeze life extension are discussed. The paper will also highlight the manufacturing challenges that were overcome to improve the environmental profiles of the products.

The paper will finally discuss the two treatments, which have been performed to date with the non-aqueous products. Initial field data demonstrates that the application of this nonaqueous product package significantly reduced the potential for formation damage and allowed the successful treatment of these wells. Residual inhibitor returns remain significantly above MIC and a long squeeze life is expected for both wells.
Development of an Enzyme Activated, Low Temperature, Scale Inhibitor Precipitation Squeeze System
Authors: McRae J. A. , Heath S. M. , Strachan C. , Matthews L. , Harris R.
Published: December 2007

Since the early 1990’s scale inhibitor precipitation technology has been routinely used throughout the North Sea to provide improved placement and extended treatment lifetimes when compared to conventional aqueous-based scale inhibitor squeeze treatments. Controlled precipitation technology is based upon the deployment of a specially formulated scale inhibitor package containing an organic additive that breaks down thermally and acts as a pH modifier resulting in in-situ scale inhibitor precipitation. However, the reliance on thermal degradation of the organic additive to cause precipitation means that this technology is limited to use in wells at temperatures > 85°C.

This paper describes the development of a low temperature, scale inhibitor precipitation delivery system. The new system is based upon the use of novel enzyme technology to break down the pH modifier using a non-thermal mechanism, thus allowing product deployment at low temperatures previously unavailable to the thermal degradation systems. Laboratory studies have so far indicated that the enzyme is effective at inducing scale inhibitor precipitation at both 40°C and 80°C.

A description of the laboratory development and evaluation of the new enzyme precipitation technology including enzyme assay, full analysis of the precipitation mechanism and core flood studies to evaluate formation damage potential and retention and release characteristics will be presented.

This paper will also highlight how the use of the enzyme precipitation process can increase squeeze lifetimes when compared to traditional adsorption squeeze treatments at low temperatures.
Scale Management of Production Wells via Inhibitor Application in Supporting Injection Wells
Authors: Ragulin V. , Mikhailov A. , Latipov O. , Voloshin A. , Tyabayeva N. , Mackay E.
Published: December 2007

At the present time, the YUKOS Oil Company is applying various techniques to maximize oil recovery. Some of these techniques, such as waterflooding, are leading to an increase in the number of wells that face scaling problems. Various technologies are being used for scale management in these wells, including, for example, continuous inhibitor dosing utilising surface dosing systems. This method has some disadvantages, including the high cost of the service. In addition, this technology only protects downhole equipment from damage by scale deposits, but the bottomhole formation zone remains unprotected. Some years ago we recommended that production wells be protected via scale inhibitor application in the injection waters used for reservoir pressure control and sweep. Experiments conducted have shown that this technique may be used for certain production well types with scaling problems when these are located in relatively close proximity to their supporting injection wells.

This paper presents the experimental and field results when this technique was tested in the South-Surgut oilfield. Before testing, a preliminary investigation of the formation geology and hydrodynamic connectivity between injection and production wells was carried out. Next, a large number of experiments were carried out to select an efficient inhibitor chemistry, to test for inhibitor adsorption on the reservoir rock, to evaluate an initial MIC for the solution, and to determine the inhibitor dosing periodicity.

During testing of this technique, the inhibitor concentration in the produced water was regularly measured, and the impact on protection against scale was continuously evaluated. It was demonstrated that the inhibitor concentration in the produced water did not decrease below 5- 10 ppm on average during 150-200 days for all wells. As a result, the interval between workovers for pump equipment increased by approximately 2.5 times. Furthermore, oil production was increased relative to the period before introduction of this technology. An economic evaluation was carried out that showed the viability of using this technology for the protection of wells in a compact injector-producer pattern.
Sulphate Removal for Barium Sulphate Scale Mitigation a Deepwater Subsea Production System
Authors: Collins I. R. , Stalker R. , Graham G. M.
Published: December 2007

Scale control is conventionally achieved by use of chemical inhibitors, introduced to the production system either by squeeze treatment into the reservoir or continual injection into the well. However, as new field developments encounter more challenging production environments or when the associated economic impact of chemical intervention is large (e.g. subsea completed wells with poor chemical placement by bullhead treatments, or limited access to wet subsea wellheads), other methods of scale control such as sulphate removal must be considered during the front end engineering design (FEED) stage.

The Greater Plutonio development, lying in deep water (500 – 1600 metres) off the coast of Angola, will be produced via multi-well subsea facilities tied back to a floating production vessel, with reservoir pressure support being provided by seawater injection. Owing to the complex and inaccessible nature of the subsea production system, chemical control of sulphate scale was considered economically unfeasible. Scale control will therefore be achieved by means of sulphate removal prior to seawater injection. However, following conventional sulphate reduction towards 40 ppm there remains a residual scale potential, the impact of which on production is difficult to assess using thermodynamic scale prediction packages or normal laboratory conditions. Periodic squeeze treatments were however still anticipated. A detailed laboratory testing programme of dynamic and static scale formation tests coupled with dynamic core-blocking tests was undertaken to determine the effect of varying production conditions, organic acid content, flow regime and the nature of the underlying substrate on scale formation under field specific conditions for this mildly oversaturated system. The ultimate goal of the laboratory test programme was to define an optimal sulphate level in the injected seawater to prevent scale formation throughout the production lifetime of the field. By comparison of laboratory test results with predicted scale formation tendencies, an acceptable level of sulphate in the injected seawater was determined which would allow pressure support without causing scale formation. This allowed further detailed analysis of the costs associated with a residual scale risk at 40 ppm sulphate (or above) with the costs associated with upgrading the SRP facility to achieve lower levels of sulphate in the injection water. The laboratory work allowed an optimal sulphate concentration to be determined which was achievable through modification of the current design facilities and resulted in a significant cost saving in the development phase.
Groet 1 Scale Study: Analysis, Diagnosis & Solution Implementation
Authors: Nieuwland H. F. , Collins I. R.
Published: December 2007

Gas well Groet 1 (GRT1), located onshore in the Netherlands, has been experiencing unstable production for six months since Q1 2002. A down hole video survey identified salt (halite) deposition in the tubing which was subsequently removed by a gauge cutter. The problem reoccurred in Q4 2002 leading to an 8.3 MBOE loss in the quarter. A scale prediction study was conducted to analyse the problem arising with well GRT1 and to diagnose whether the scaling problem is transient or persistent. This study indicated that the scaling behaviour is persistent. Several remedial actions and control options were considered, based upon the diagnosis. All of the remedial actions and control options were compared on a risk / cost / benefit basis. The outcome of this study was that the most economical and lowest risk halite control option was bi-weekly fresh water soaks.
pH-Stabilisation, a Reliable Method for Corrosion Control of Wet Gas Pipelines
Authors: Dugstad Arne , Seiersten Marion
Published: December 2007

The pH-stabilisation method is a cost effective, reliable and environmental friendly way to control corrosion in gas/condensate pipelines where glycol is used as hydrate preventer. Increasing the pH to 6.5-7.5 facilitates the formation of a protective iron carbonate film on the steel surface and reduces corrosion of the steel.

The carry-over of formation water puts limits on the use of the pH stabilisation technique as carbonate scale may form. Scale formation in glycol carrying pipelines is not easy to predict, as solubility data for CO2 and scale forming compounds in glycol solutions are very scarce. Glycol affects scale formation by changing the solubility and the precipitation kinetics, and the solubility of for instance calcium carbonate is markedly reduced.

The paper reviews the experience from the fields that have been pH stabilised and discuss the various pH-stabilisation methods that have been used. The paper gives data on the application limits with respect to formation water and discuss operational problems, challenges and solution related to the risk for scaling downstream the lean MEG injection point, in heat exchangers and in the MEG regeneration and reclamation systems.
Corrosion Behavior of Various 13 Chromium Tubulars in Acid Stimulation Fluids
Authors: Ke Mingjie , Boles Joel
Published: December 2007

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

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

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

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

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

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 (< 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

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

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

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

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

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.