bluuebunny/crossref_metadata_2025 huggingface dataset:
Basin-wide impacts of compounds with estrogen-like activity on longnose dace (Rhinichthys cataractae) in two prairie rivers of Alberta, Canada
Authors: Jeffries Ken M , Nelson Erik R , Jackson Leland J , Habibi Hamid R
Published: April 2008

Environmental compounds with estrogen- or antiestrogen-like activity can enter rivers from multiple sources, including municipal wastewater and agricultural runoff. We used longnose dace (Rhinichthys cataractae) to investigate exposure to compounds with estrogen-like activity, which we measured in water at multiple sites in the Oldman and Bow rivers (AB, Canada). We evaluated changes in vitellogenin mRNA with quantitative reverse transcription–polymerase chain reaction, then compared vitellogenin levels to sex ratios and fish performance indices to assess how exposure to compounds with estrogen-like activity affects longnose dace populations. Vitellogenin levels were elevated at least 59 to 110 km downstream of municipalities. In the Oldman River, increased vitellogenin expression and female-biased sex ratios suggest severe endocrine disruption, likely resulting from the combined impacts of municipal wastewater, agriculture, and large cattle operations within the basin. In the Bow River, municipal wastewater may be the major source of compounds with estrogen-like activity that affect longnose dace. The sex ratios were not heavily skewed, as in the more agriculturally influenced Oldman River. We detected organic contaminants in river samples at every site, but the highest concentrations were found downstream of municipalities and in areas with intense agriculture. Vitellogenin levels and sex ratios of longnose dace suggest basin-wide exposure to compounds with estrogen-like activity. Our results demonstrate that it is important to assess rivers at large spatial scales to detect fully the impacts of municipal wastewater and agriculture on fish populations.
Implant Placement at the Time of Mandibular Molar Extraction: Description of Technique and Preliminary Results of 341 Cases
Authors: Fugazzotto Paul A.
Published: April 2008

Background: Theoretically, the ability to place implants in ideal positions at the time of mandibular molar extraction with concomitant regenerative therapy would simplify and shorten the course of therapy for patients.

Methods: A total of 341 implants were placed in 320 individuals at the time of mandibular molar hemisection and extraction. Concomitant regenerative therapy was performed around 332 of the placed implants. No regenerative therapy was performed around the remaining nine implants. Eleven additional sites, in which simultaneous implant placement was planned, were treated instead with regenerative therapy alone using graft material and a covering membrane. Implants were placed in these sites in subsequent surgical visits.

Results: One implant was mobile 3 weeks postinsertion. A second implant was lost after 30 months in function. All other implants were stable at the time of uncovery 3 to 7 months postinsertion. A total of 339 implants have been in function for up to 6 years, with a mean time in function of 30.8 months, yielding a cumulative survival rate of 99.1%.

Conclusion: Implants may be placed in ideal restorative positions at the time of mandibular molar extraction with or without concomitant regenerative therapy.
Chronic Stress May Modulate Periodontal Disease: A Study in Rats
Authors: Peruzzo Daiane C. , Benatti Bruno B. , Antunes Isabela B. , Andersen Monica L. , Sallum Enilson A. , Casati Márcio Z. , Nociti Francisco H. , Nogueira‐Filho Getúlio R.
Published: April 2008

Background: The present study aimed to evaluate whether chronic stress (CS) affects ligature‐induced periodontal disease and to investigate the impact of CS on the mRNA levels of interleukin (IL)‐1β, −1 receptor antagonist, −6, and −10, interferon‐gamma (IFN‐γ), receptor activator of nuclear factor‐kappa B ligand (RANKL), and osteoprotegerin in the gingival tissues of rats.

Methods: Sixty male Wistar rats were assigned randomly to three groups: G1 (control; non‐ligated sites), G2 (periodontal disease), and G3 (periodontal disease associated with restraint stress for 12 hours/day for the entire study). After 30 days, all animals were sacrificed by decapitation. Blood samples were taken, and the concentrations of corticosterone and catecholamines were measured as biomarkers of CS. Marginal tissues around ligated and non‐ligated teeth were harvested, and gene expression was assessed by quantitative polymerase chain reaction. Moreover, the area of bone loss (ABL) was determined histometrically.

Results: Data analysis showed that CS increased serum levels of stress biomarkers (P <0.05), ligature placement resulted in a significant ABL compared to non‐ligated sites, CS significantly increased the amount of ABL in inflamed sites (P <0.001), and CS significantly increased mRNA levels of proinflammatory (IL‐1β and −6 and IFN‐γ) and anti‐inflammatory (IL‐10) cytokines and proresorptive factor (RANKL) in ligated sites (P <0.05).

Conclusion: CS significantly increased bone loss resulting from ligature‐induced periodontitis by a local increase in proinflammatory and proresorptive factors.
Cellular Motility of Down Syndrome Gingival Fibroblasts Is Susceptible to Impairment by Porphyromonas gingivalis Invasion
Authors: Murakami Jumpei , Kato Takahiro , Kawai Shinji , Akiyama Shigehisa , Amano Atsuo , Morisaki Ichijiro
Published: April 2008

Background: Severe periodontal breakdown is often associated with Down syndrome (DS); however, the etiology of this condition is not understood fully. Cellular motility of gingival fibroblasts is a critical event for wound healing and regeneration of periodontal tissues. Porphyromonas gingivalis is known to be a periodontal pathogen that invades host cells, contributing to periodontal destruction. In this study, we examined the influence of P. gingivalis infection on the motility of DS gingival fibroblasts (DGFs).

Methods: DGFs and normal gingival fibroblasts (NGFs) were infected with P. gingivalis with type II fimbriae, and cellular motility was evaluated using an in vitro wounding assay. Protein degradation of α5β1‐integrin subunits and a migration‐regulating signaling molecule, paxillin, were investigated using specific antibodies. The adhesion to and invasion of fibroblasts by P. gingivalis were determined with a colony forming assay. The gene expressions of α5β1‐integrin subunits were also quantified using a reverse transcription‐polymerase chain reaction method.

Results: The cellular motility of DGFs was impaired significantly by P. gingivalis compared to NGFs, and the former were invaded readily by P. gingivalis. Further, cellular paxillin from DGFs was degraded markedly by the pathogen. Although protein degradation of α5β1 integrin was induced, its mRNA expression was not affected significantly.

Conclusions: P. gingivalis readily invades DGFs and subsequently degrades paxillin, which impairs cellular motility and likely prevents wound healing and the regeneration of periodontal tissues. These characteristics may be involved in the etiology of DS periodontitis.
Microbiologic and Immunologic Characteristics of Periodontal Disease in Hispanic Americans With Type 2 Diabetes
Authors: Ebersole Jeffrey L. , Holt Stanley C. , Hansard Richard , Novak M. John
Published: April 2008

Background: The microbiology of periodontitis in type 1 diabetes has been reported, but less is known about type 2 diabetes. Moreover, these data have not linked microbial colonization, host response, and clinical presentation in type 1 or type 2 diabetes. The objectives of this study were to relate periodontal status, periodontal microorganisms, and host‐response characteristics in Hispanic Americans with type 2 diabetes.

Methods: Plaque and serum samples were obtained from 63 Hispanic American subjects with and without type 2 diabetes. The microbiology of subgingival plaque samples was evaluated using DNA checkerboard hybridization, and serum antibody to a battery of oral microorganisms was determined using an enzyme‐linked immunosorbent assay.

Results: In general, similar pathogens were present in periodontitis sites from subjects with and without type 2 diabetes, although the periodontitis sites in diabetes showed a higher frequency of Porphyromonas gingivalis, Aggregatibacter actinomycetemcomitans (previously Actinobacillus actinomycetemcomitans), and Campylobacter spp. Serum antibody to Campylobacter rectus was elevated in type 2 diabetes, whereas antibody to P. gingivalis and C. rectus were elevated in subjects with periodontitis, irrespective of diabetes status. Stratification of the population based upon antibody to P. gingivalis or C. rectus suggested a linkage between elevated antibody to P. gingivalis, increased frequency of diabetes, and significantly worse periodontitis.

Conclusion: The increased severity of periodontal disease with type 2 diabetes may reflect an alteration of the pathogenic potential of periodontal bacteria and/or a modification of the characteristics of the host's inflammatory response that may contribute to a breakdown in the homeostasis of the periodontium.
Root Proximity as a Risk Factor for Progression of Alveolar Bone Loss: The Veterans Affairs Dental Longitudinal Study
Authors: Kim Taera , Miyamoto Takanari , Nunn Martha E. , Garcia Raul I. , Dietrich Thomas
Published: April 2008

Background: The purpose of the present longitudinal study was to evaluate the association between root proximity and the risk for alveolar bone loss (ABL).

Methods: We used data from the Veterans Affairs Dental Longitudinal Study, a closed‐panel longitudinal cohort study of 1,231 men enrolled in 1968 with triennial follow‐up examinations. Periapical radiographs of mandibular incisors from subjects with ≥10 years of follow‐up were selected. Interradicular distance (IRD) at the cemento‐enamel junction and alveolar bone levels at baseline and last follow‐up were measured using digitized radiographs. The rate of progressive ABL was determined and expressed as millimeters per 10 years. Site‐specific multivariate regression models were fit to evaluate the association between IRD and ABL rate, adjusting for age and smoking. Empirical standard errors and generalized estimating equations were used to account for the correlation among sites within subjects.

Results: There were 473 dentate subjects, aged 28 to 71 years at baseline, with ≥10 years of follow‐up data available for analyses. The mean follow‐up time was 23 years. The mean IRD was 1.0 ± 0.3 mm, and the mean ABL rate during 10 years was 0.61 ± 0.59 mm. There was a significant non‐linear association between IRD and ABL rate (P <0.005). Compared to sites with IRD ≥0.8 mm, sites with IRD <0.6 mm were 28% (95% confidence interval [CI]: 11% to 48%) more likely to lose ≥0.5 mm of bone during 10 years (relative risk: 1.28 [95% CI: 1.11 to 1.48]) and 56% (95% CI: 11% to 117%) more likely to lose ≥1.0 mm of bone during 10 years (relative risk: 1.56 [95% CI: 1.11 to 2.17]).

Conclusions: IRD <0.8 mm is a significant local risk factor for alveolar bone loss in mandibular anterior teeth. Measurement of IRD may have important prognostic value in making treatment decisions.
First Production Log Run in a Heavy-Oil Long-Horizontal Well Through a Y-Tool and Premium Screens
Authors: Montero Jacobo , Salazar Namir , Fondyga Tony , Reyes Kerwin
Published: April 2008

The first production log ever run in a heavy oil, long horizontal well completed with premium screens in open hole and through a Y-tool was successfully executed by Petroregional del Lago S. A. (a joint venture between PDVSA and Shell) in the Urdaneta West Field (Lake Maracaibo, Western Venezuela). The purpose of the job was to identify the origin of water in a well that experienced water break-through from the first day of production. A specialized set of logging tools was run to detect both water and oil flow, as well as to determine any flow behaviors like cross-flow that would help understand the source of water in the formation, obtain sufficient data to prepare a water shut-off program, and establish basic productivity information from the well, being this also the first production log run in the heavy oil wells in the field, which require artificial lift to flow. The results of the production log indicate that a sand package is producing water from an unexpected zone, which will require a water shut-off workover. This paper describes the planning, operational and interpretation processes of the logging activity, and presents a number of lessons learnt and useful recommendations for similar activities in heavy oil wells.
Effect of External Mechanical Damage on the Fatigue Life of Coiled Tubing Exposed to Sour Environments
Authors: Padron Tomas
Published: April 2008

In normal operations, coiled tubing (CT) is frequently subjected to mechanical damage on its outer surface that could adversely affect its fatigue life. The effect of transverse external mechanical damage, with depths in the range of 10% to 20% of the nominal wall thickness, on the fatigue life of grades 90 and 110 CT samples exposed to sour environments (i.e. solution NACE A saturated with 100% H2S) was reported in a previous paper (SPE 107113). The results showed that the fatigue life of the pipe was reduced significantly when the samples were pre-exposed to the sour environment used for these experiments. Additional testing was subsequently performed to asses less severe damage depths (i.e. < 10%) and orientations (i.e. longitudinal), less severe environmental conditions (i.e. H2S concentrations lower than 100%), application of anti-cracking inhibitors, and the response of other CT grades (example: grade 100).

The present paper summarizes the results from the fatigue testing of more than 100 CT samples (grades 90, 100 and 110) with artificial mechanical damage in the transverse and longitudinal orientations, and depths from 5% to 20% of the nominal wall thickness, after being exposed to different sour environments (H2S concentrations from 1% to 100%) and including three different anti-cracking inhibitors.

A comparison between the sour fatigue life of the samples containing external mechanical damage and that of samples without damage is presented in terms of percentages of sweet life (i.e. fatigue life measured in air). Also, the effects of the damage depth and orientation, H2S concentration, and anti-cracking inhibitors on the fatigue life are analyzed. Finally, an inspection criterion for mechanical damage on strings to be used in sour environments is proposed.
A Field Study of Coiled-Tubing Material Loss and Ovality
Authors: Boles J. , Burgos R. , Medina A.
Published: April 2008

Coiled-Tubing (CT) integrity remains at the forefront in the mind of end users, particularly in high-end applications. The properties of a CT string, including ovality and wall thickness, change over time when it is run into and is pulled out of a well, due to a number of wear factors and a combination of them, including well trajectory, fluid properties, the CT properties and the applied external forces.

A typical CT string is exposed to a variety of applications during its lifetime, each having a different effect on the material. Ovality and wall thickness loss thus become critical telltale indicators for the condition of the pipe and its potential serviceability. Devices for ovality and wall thickness measurement, whether performed off-line or real time during a job, are readily available.

This paper demonstrates how one such device has been used for various services with CT, including acid stimulation work in Saudi Arabia, CTD work in Alaska, Nitrogen kick off, clean out and CT spooling in Columbia and extensive eLine operations in the Barnett Shale, Texas. These case studies will show the evolution of material loss and ovality and how the information can be used to monitor and maximize the life of the CT string in a way that no other technique or model is capable.
Through-Tubing Inflatable Technology Deployed on a Downhole Tractor System Provides Real-Time Cost Savings
Authors: Kelbie Graeme M. , MacKay John D.
Published: April 2008

Finding new ways to reduce the costs and production of unwanted water are of paramount importance to the upstream oil and gas industry. The continued discovery of marginal developments, the depletion of reserves from the more mature fields, and a worldwide increase in extended reach and horizontal drilling all provide new challenges on a daily basis. An economical and reliable method of performing zonal isolations and shutting off the unwanted water in these wells can be accomplished with through-tubing inflatable high-expansion devices. However, in the more extended reach and horizontal wells previously requiring coiled tubing or snubbing, there is a new alternative. To meet the reliability, time, and cost efficiency demands of the industries’ current fast pace environment, the downhole tractor system offers an effective new avenue for deployment of these isolation devices.

In this paper we will focus on a case history showing how the use of through-tubing inflatable technology run in conjunction with a downhole tractor system provides zonal isolation, and savings in time and cost in traditional rig and coiled tubing markets. The other added benefit that is so important is the reduced HSE risk from lighter lifts, reduced personnel and the fluid handling issues surrounded by the use of kill fluids is not needed because the operation is conducted without the need to kill the well.
Coiled-Tubing-Conveyed Proppant Treatment Yields Increase in Production Efficiency and Return on Investment
Authors: Peak Zeke T. , Montes Matthew B. , Natenberg David , Durkee Marc
Published: April 2008

Formation sand production and stimulation proppant flowback are large and costly production problems in maturing assets. Recently, a new coiled-tubing-conveyed proppant treatment (CTCPT) was applied for the operator in the Carr-Lundell field in Webb County, Texas. This technology effectively eliminated the production of formation solids and stimulation proppant. The result yielded increased efficiency in associated production time and decline rates, which have optimized return on investment. The new treatment has also reduced residual operational expenditures by eliminating costly workovers, equipment repair, and lost production caused by this escalating industry problem.
An Isolation and Remediation Solution for Wellhead Maintenance in the North Sea
Authors: Petrone Daniele , Rice Phillip , Pedersen Jørgen Hoj , Stjernholm Anders
Published: April 2008

Internal corrosion is prevalent in offshore wellheads in the Siri field in the Danish North Sea. Certain wellhead components must be replaced with corrosion-resistant parts. During the wellhead maintenance work, local regulations require a dual barrier and each of these barriers must be tested independently. The casing below the wellhead is completed with fiberglass lining. Standard bridge plugs and standard cleaning methods of tubing are incompatible with the lining and are not considered feasible.

This paper presents an alternative solution that uses two inflatable bridge plugs as an isolation method and provides the ability to remove the scale present in the well in the setting area. It details yard tests performed to ensure the chosen technique does not damage the lining of the tubing and can efficiently isolate the wellhead. It also reviews results of several operations performed between 2006 and 2007, in which inflatable bridge plugs were successfully set and retrieved in the fiberglass-lined tubing.
The Operational and Economical Impact of CT Spoolable Connectors During the Last Five Years in the Norwegian and Danish Sector of the North Sea: Case Histories
Authors: Sach M. , Maribu K. , Haga J. , Nesvik K. T. , Boye-Moller C.
Published: April 2008

Coiled Tubing (CT) equipment in the Norwegian sector of the North Sea has traditionally been heavy, due to CT reels using larger sizes of CT – a trend also observed in other areas. Due to the requirement of performing well interventions in longer wells and larger completion sizes, CT drums weighing 40-60 t have been utilised. Not many platform cranes are capable of lifting such heavy CT drums and during bad weather periods operations are often delayed, even when using significantly lighter CT drums. Using spoolable CT connectors allow for a long and heavy CT string to be lifted on board of a platform on two or more separate drums and joining them together again once onboard. More than 50% weight reduction has been achieved making operational schedules more predictable. In the geographical areas considered, spoolable CT connectors have outperformed traditional methods like boat spooling and butt-welding from a safety, operational and economical point of view.

Due to the reduction in weight, larger CT sizes have become available on older platforms as well. New CT applications that were previously considered unfeasible, like selective, high-rate acid fracing through CT, have been performed, extending the capabilities of CT interventions beyond previous logistical and technical limits. Being able to select the correct size of CT, with less dependency on offshore crane limits and weather has a fundamental impact on the usage of CT in the offshore industry.

Rather than discussing the spoolable CT connector itself, the primary intention of the paper is to re-view case histories that were performed during the last 5 years. Operational challenges that have been mastered, successes, failures and further developments are presented. A new CT reel configuration to simplify spoolable CT connector installation will be presented. The new applications made possible by this technology and their economic impact on the Norwegian CT market since year 2003 will be reviewed.
Flow Properties and Drag-Reduction Characteristics of Surfactant-Based Fluids (SBF) in Large-Scale Coiled Tubing
Authors: Kamel A. H. Ahmed , Shah S. N.
Published: April 2008

In spite of their wide use as friction reducer or fracturing fluid due to their unique characteristics, there is a very little information available in the literature about surfactant based fluids. Majority of this information is related to straight tubing with small sizes. Data of larger sizes as well as coiled tubing are very scarce. Furthermore, previous studies have correlated drag reduction behavior of these fluids only through simple power-law parameters. Little is known regarding the importance of elasticity on drag reduction of SBF. Scale-up factor is yet another problem.

This study aims at understanding the viscoelastic behavior of SBF and its effect on drag reduction in large-scale CT. The properties of widely used Aromox APA-T, a highly-active surfactant used as gelling agent in aqueous and brine base fluids, are investigated. Rheological and viscoelastic measurements are conducted for concentrations 1.5, 2, 3, and 4% vol. using Bohlin rheometer. Flow tests are conducted using ½- and 1½-in. CT with various curvature ratios. This study is the first investigation of flow behavior of SBF in a large-scale CT.

The results show that SBF exhibit a non-Newtonian pseudo-plastic behavior. Formation of rod-like micelles (emergence of viscoelasticity) is found to be affected by surfactant concentration and shear exerted on the fluid, which in turn, affects drag reduction characteristics. Also, simple correlations using only rheological properties may lead to erroneous results, especially when scaled-up to a large-scale.
Stimulation With Coiled Tubing and Fluidic Oscillation
Authors: Ulloa Gutiérrez Joel Vladimir , Callarotti Gian Franco , Akrich Oscar , Monroy Rafael Rodríguez
Published: April 2008

To enhance stimulation treatment placement and effectiveness in highly deviated and deep wells, a coiled-tubing intervention was designed and implemented using a fluidic oscillator. The stimulation treatments were developed to mitigate damage caused by fines migration, water blockage, scale, and asphaltenes; such damage is typically located in the near-wellbore area.

Traditionally in southern Mexico, stimulation treatments in highly deviated and deep wells were bullheaded from the surface using diversion techniques. Results from these treatments were not always satisfactory.

A fluidic oscillator was used as a placement technique for these stimulations. This tool, with no moving parts, generates a change in fluid direction that creates a low-amplitude pressure pulse at a frequency range from 300 to 600 Hz.

The synergy from the use of coiled tubing, a fluidic oscillator, and a tailored stimulation treatment was proven effective in stimulating these wells, achieving excellent results.

Case histories from four wells are presented: Samaria 1129, Iride 154, Jujo 654, and Mora 3.
Coiled Tubing and Nitrogen Generation Unit Operations: Corrosion Challenges and Solutions Found in Brazil Offshore Operations
Authors: Duque Luis H. , Guimarães Zacarias , Berry Sandra L. , Gouveia Manoel
Published: April 2008

For several years, coiled tubing offshore operations in Brazil have involved the use of nitrogen generation units. Remote locations, lack of liquid nitrogen suppliers and logistical issues, among others, have driven the main oil operator to increase the use of Nitrogen Generation Units.

Using a Nitrogen Generation Unit in remote locations, where most of the platforms have very limited space, was the ideal solution for a very old problem of supplying nitrogen. However, when the use of the Nitrogen Generation Unit was combined with coiled tubing operations, another concern arose.

In-situ nitrogen generation does not generate pure (99.9%) nitrogen gas. In-situ nitrogen generation can generate nitrogen gas compositions with oxygen contents as high as 5%. Nitrogen with oxygen contents as high as 5%, under downhole conditions of pressure and temperature, can result in severe corrosion problems in the coiled tubing string. Furthermore, together with the increased oxygen content, fluid systems such as completion brines and acids were pumped, which also increased the severity of the corrosive environment. Sometimes operations were stopped because the coiled tubing Bottom Hole Assembly (BHA) was completely plugged by oxidized/corroded metal solid flakes or the coiled tubing string became so corroded that it required inspection before further use in job operations. Based on these corrosion and safety issues the use of in-situ nitrogen generation loses its benefits.

To find a solution to this corrosion problem, a laboratory research study was performed with the most commonly used coiled tubing string material and the pumped treatment fluids under surface and downhole conditions with the maximum percentage of oxygen concentration that could be expected in operations. Several corrosion inhibitors and mixtures were tested for their ability to control the corrosion of the coiled tubing string.

After laboratory testing established which inhibitor systems would control the corrosion rate of the coiled tubing, yard tests were performed to confirm that the inhibitor would work in the field. After the field trial was performed successfully with several applications, the recommended practices were adopted from this research to avoid the corrosion problem faced in the past with the use of offshore nitrogen generation units.

This paper presents the sequence of events of this project: the coiled tubing corrosion observed in the laboratory research studies, the performed yard trials; the recommended field applications, as well as the benefits that this study and final application brought to the operations.
New Hydrajet Tool Demonstrates Improved Life for Perforating and Fracturing Applications
Authors: Surjaatmadja Jim B. , Bezanson Jeff , Lindsay Sharlene , Ventosilla Pedro , Rispler Keith
Published: April 2008

Hydrajet perforating and fracturing has recently gained popularity in the oilfield industry, especially when used with coiled tubing (CT). With coiled tubing, the task of placing many cuts at multiple places becomes straightforward and no longer time consuming. However, hydrajetting equipment life has been plagued with rapid failures, resulting in the need for time-consuming and costly tripping out and in the hole for jetting tool replacement.

To reduce or eliminate such tripping costs, substantial improvements of the hydrajetting tools are required. A mere change of materials or a redesign using concepts that follow the customary models has resulted in insignificant performance improvements. It was therefore decided that a complete overhaul of the design concepts needed to be made. By doing this, substantial improvements can be obtained.

This paper discusses unique improvements that have been made to the hydrajetting tools. The new tools address the aspects that have contributed to failures in the past. By taking a fresh perspective of this situation, a performance improvement of 200–300% can be attained. Recent perforating and stimulation experiences in the field demonstrate this and are discussed.
Coiled Tubing Jet Drilling With a Downhole Intensifier
Authors: Kolle J. J. , Theimer K. , Theimer A. , Cox R. , Schershel S. R.
Published: April 2008

High-pressure rotary jet drilling holds the promise of increased rate of penetration with reduced weight-on-bit, torque and vibration levels. A high-pressure rotary jet drill, pressure intensifier and gas separator have been developed to allow jet drilling using conventional surface pumping equipment and coiled tubing. High-pressure reaction turbine jet rotors have been developed for drilling holes ranging from 1-1/8" to 3-5/8". Jet drilling tests have shown that 70 MPa (10,000 psi) jets can effectively drill most conventional oil and gas producing formations. Conventional pumps, swivels and tubing operate at up to 28 MPa (4000 psi). A 2.5:1 pressure intensifier was developed to allow jetting at the pressure required for effective drilling. The intensifier can operate on two-phase flow using a downhole gas separator. In two-phase operation the separated gas is used to power the intensifier and the high-pressure water is provided to the jetting nozzles. The gas exhaust from the intensifier is ported to the drilling head to extend the range of the jets.

Tests have demonstrated that the jet drilling BHA is capable of cement milling but rates of penetration are lower than a motor and mill and the pumping pressures required are higher. The tools could find applications in situations where a motor cannot be used. For example the tools could power a small diameter lance jet drill through an ultra-short radius curve for lateral drilling. Well service applications include removal of hard scale without risk of damage to damage to downhole equipment.
Cutting Concentric Casing Strings With Sand Slurry
Authors: Hebert Galen Roy , Sackash Mark , Hogan Richard
Published: April 2008

Operators needing to cut single or concentric casings to facilitate well abandonment or for other purposes can use a slow-rotating hydroblast motor with a jet cutter head on drillpipe. This combination is capable of operating with tight clearances.

This case history describes an operation wherein a jet cutter on a rotating motor was used to cut two components of a casing string, a 7-in. liner inside a 9 5/8-in. casing, at 400-ft depth. The well required abandonment, and the casing string was damaged, with a sharp bend that limited the tool size that could be used.

Chemical cutting and mechanical cutting were considered, but the casing damage and size limitation it imposed caused the service company to recommend deployment of a slow-rotating motor and jet cutter head conveyed downhole on 2 7/8-in. drillpipe. The slurry pumped through the cutter was sand carried by seawater, gelled with a polymer. The 7-in. liner was cut first and removed from the well. The 9 5/8-in. casing was cut and removed to enable well abandonment procedures.

The paper presents (1) discussion of the issues that led to use of the rotating motor setup, (2) treatment plan, and (3) execution procedures.
Planning for Successful Rig Assist HP/HT Cleanout Operations
Authors: Lamont Alan , Radcliffe Paul , Klinck Mark , Brumfield John , Bell Gavin
Published: April 2008

This paper describes the equipment and techniques that were used for a high-pressure, high-temperature (HPHT) cleanout operation carried out on the Shearwater platform in the UK central North Sea with the support of a jackup drilling unit. The project involved intervention in three wells over a period of 9 months. The wells had been shut in for some time following production of reservoir solids. A hydraulic workover unit (HWU) was selected to clean out the production tubing to allow isolation barriers to be installed.

In rig-assist mode, the HWU deploys pipe against surface pressure with the rig providing pipe-handling support. The paper details the planning and pre-engineering work that preceded offshore operations. Detailed planning and risk assessment were also required during operations because well conditions changed. Some equipment problems required a review of planned operations, and during an annual process plant shutdown, onshore tests were carried out before mobilization for the second phase of the intervention project.

Modifications were required to the HWU to withstand the high buckling loads associated with snubbing against high pressure. Additionally, special downhole tooling was required to accommodate extreme well conditions. The paper discusses the development work involved and the subsequent performance of the equipment.

Operating performance statistics and key lessons learned during the project are presented.
Unique Application of Coiled Tubing and Inflatable Packer Technology Leads to Successful Deoiling of Damaged Pipeline in Gulf of Mexico
Authors: Quintero Ignacio , Murphy Bob , Maddox Joe , Noddin John , Coles Robert
Published: April 2008

In July 2005 during Tropical Storm Cindy the pressure balance safety joint on the 8" crude oil riser at the West Delta 109A platform was separated. Subsequently, measures were taken to de-oil the first 5000ft. of the separated end of the pipeline. Before further action could be taken, Hurricane Katrina passed through the area resulting in further movement of, and substantial damage to, the pipeline. Divers did locate the line at a point some 4500ft from the platform and subsequently discovered that some 7000ft. of it was buried under mudslides further downstream of the platform.

The pipe line damage could not be repaired due to its' being buried under mudslides, therefore a unique approach was taken. Cuts were made at each end of the damaged pipeline, flanges and shut off valves were installed and a 4" pipe riser was then made up to one end, picked up and tied back to the service barge some 500 ft away thus creating an engineered radius suitable for coiled tubing (CT) operations. The CT unit was then made up at an angle of 15° to the vertical and an inflatable plug run into the riser, thence into the 8" line until it could go no further. The plug was then inflated and tested, the disconnect was activated and the crude oil in the line flushed out with sea water to the barge tanks until the returns were clean. The CT was pulled leaving the plug in place and the same procedure was repeated at the other end of the damaged section. In this way some 4190ft of the buried line was safely de-oiled leaving the balance isolated between the two inflatable plugs.

In this paper the authors will review the pipeline damage and discuss the various options considered to make the line safe and prevent leakage and environmental damage in the future. They will go on to describe in detail the preparation for, and the successful performance of, this CT deployment, the first of its' kind in the Gulf of Mexico. They will conclude that this pioneering operation can serve as a model for several such pipeline situations which the MMS has mandated should be fixed by 2010.
Case History: Extended-Stroke Downhole Power Unit Successfully Pulls Subsea Wellhead Plugs
Authors: McDaniel Dennis , Cromb John , Walton Jim , Clemens Jack , Moore Darrell , Huggins Jeff
Published: April 2008

As exploration continues to venture into more challenging environments, service companies have had to increase their scope of capabilities to meet the challenges brought about by the new environments into which the oil and gas industry has ventured. One of these areas has been the deepwater subsea arena. This paper will focus on one of the slickline innovations — an extended-stroke electro mechanical device — that enables performance of deepwater subsea well interventions more cost-effectively than other service alternatives.

Today's needs to provide deepwater subsea well servicing has created many new challenges for the industry. For example, pulling a deepwater subsea wellhead or crown plug can require an extreme pulling force. The difficulties experienced can be compounded by conditions that occur when the plug has been in place for extended periods of time as well as the more demanding deepwater conditions, such as high differential forces and settlement on top of the plug that contribute to the need for the higher pulling forces. These conditions often exceed the capabilities of conventional slickline services.

An option that has met other challenges in difficult scenarios is a slickline-deployed electro-mechanical device that produces a high linear pulling force directly at the wellhead plug without jarring. This tool does not require explosives or hydrostatic setting tools because it is operated by batteries. Since first being introduced, the electro-mechanical device has undergone several changes that have increased its capabilities and functionality. For example, it has recently been configured for pulling subsea wellhead plugs.

This paper will present a case history that details the first use of the ‘extended stroke’ electro mechanical device in the Gulf of Mexico in which it was capable of pulling plugs at a water depth of 5,339 feet. Using the electro-mechanical device with slickline instead of coiled-tubing resulted in a substantial savings in both the cost of deployment and rig time.
Extending Mature Field Life Using an Innovative Surface Controlled Subsurface Safety Valve (SC-SSSV)
Authors: Lalanne Philippe , Ducasse Alain , Barzu Emile , Millet François , Petit Hervé , Wallez Gery
Published: April 2008

A common cause of failure with surface-controlled, subsurface safety valves (SC-SSSV) is a defect in the down-hole hydraulic line, which controls the valve from the surface. Such a failure generates production losses and requires the intervention of a costly workover rig – usually not immediately available. In order to alleviate this type of situation, a system has been developed where the physical control line has been replaced by a communication system based on electromagnetic waves. The surface emitter continuously sends a signal to the SC-SSSV. Both items are designed to be fail-safe. The normally-closed valve remains open while receiving the signal and closes as soon as the signal is lost. This innovative, control-line free, wireline-retrievable SC-SSSV can be set in any landing nipple profile or anywhere in the tubing using monobore lock technology without a workover or well head modification.

The primary application is to secure wells with a damaged or blocked control line, damaged landing nipple, or wells completed without an SC-SSSV. It provides an immediate cost-effective solution – allowing production to resume with a surface-controllable safety barrier while avoiding or postponing a costly workover. With the arrival of this technology, sub-standard and temporary solutions, such as the normally-open velocity and ambient valves, no longer need to be considered. Another application is to free up a hydraulic SC-SSSV landing nipple in order to install a device like a capillary string for chemical or gas injection at the bottom of the well safely.

A prototype has been built and successfully tested for six months in a flowing gas well with 15% H2S – the case history is presented. The tool has proven to be easy to install and reliable. Deployment will start in 2008. Thousands of wells are concerned around the world.

This breakthrough slickline product offers new possibilities for safely and efficiently managing the countless failures of hydraulic SC-SCSSVs. Its versatility brings a reduction in production losses and provides the user with a cost-effective and reliable solution.
RFID Actuation of Self-Powered Downhole Tools
Authors: Snider P. M. , Doig Tom
Published: April 2008

The emergence, development and first implementation of RADIO FREQUENCY IDENTIFICATION (RFID) technology used to actuate self powered downhole tools are discussed. A case history is also presented.

Daily contact with RFID technology is all but inescapable. Typical uses include toll road monitoring, retail inventory control, banking and tracking of livestock and pets.

RFID as an enabling technology was recognized for its potential to replace and/or complement existing methods of downhole communication, such as wired coiled tubing and downhole tubulars, ball drop operations, fibre optics, i-wire and EM telemetry. Additionally, the prospect of actuating self-powered downhole tools created an attractive and potentially highly rewarding improvement in operating costs at the wellhead through a reduction in third party wellhead asset value, less time in the hole, reduced number of trips and multi functional capabilities.

RFID in this application has two inherent parts. The TAG, which is encoded with the appropriate command data.The READER which is housed in the downhole tool.

The encoded tag is released into the well at surface from where wellbore flow of fluids, gas or condensate transports it down the well tubulars until it passes through the reader antenna. The high power antenna within the downhole tool energises the passive tag then reads and stores the tag data. Typically the tag data will consist of a command to actuate the tool by means of a self contained hydraulic pump, electric motor and battery pack. Operations such as opening and closing valves, indexing and release mechanisms and a multiple of other functions can be implemented. Multiple tools can be run at the same time without compromising the tool internal diameter. Each tool has a unique address therefore tags can be coded with data that picks out an individual tool to be actuated. Time delays and repeat sequence commands are all possible.

The case history presented in this paper describes the use of this technology to open and close a drilling circulation sub. The tool was run by a North Sea operator as part of a drilling operation. The circulation sub was opened at a depth of 10,100 ft. by flowing an "Open" command tag from the surface. After circulating, the tool was closed by flowing a "Close" command tag.
Effective Approach for CT Interventions on Inaccessible Offshore Platforms in the North Sea
Authors: Cochran Jamie , Petrone Daniele , Clubb Alexander , Greig Scott
Published: April 2008

Approximately 50% of all installations in the UK offshore sector are small steel jacket structures that are normally unmanned. These platforms often have severe limitations on the permissible lift weight of temporary well servicing equipment. During a study into the extent of this problem, it was observed that a significant proportion of gas production is reliant on wells producing via these normally unmanned installations, and that production from this source has declined dramatically in recent years. When compared to manned installations where (intervention is easier and therefore assumed more frequent), production decline is less severe.

An operator identified a production enhancement opportunity on an unmanned installation in the North Sea UK Sector. The well needed extensive intervention in order to be brought back to production using coiled tubing (CT). Due to the restricted crane capacity (less than 7.5 ton) on the platform, a conventional CT package could not be lifted on board. Through a collaborative project, an existing CT equipment package was modified to be lifted within this weight limit.

A boat spooling technique was used to install the CT string onboard the platform without using a crane as it was much heavier than the crane limit. Throughout the equipment modification project, the principles of efficient rig up and optimized fast, safe working where applied. The installation of this equipment on the platform was conducted quickly and easily, validating this approach and improving on previous experiences significantly.

This paper demonstrates how conventional equipment can be adapted to meet the challenges faced with platforms considered inaccessible to perform CT interventions.
Innovative Tool for Coiled-Tubing Depth Measurement Increases Productivity and Minimizes Costs While Improving Accuracy and Safety
Authors: Ohaegbu Paul I. , Minish Sheldon , Morris Collin , Boyd Doug
Published: April 2008

Traditionally, coiled tubing (CT) counters have been mounted above the injector and typically on a levelwind between the coiled tubing reel and the injector. This tends to expose the coiled tubing counter to vibrations, jerks and slippage as the levelwind traveling head assembly slides from side to side and the coiled tubing is run in to the well or pulled out of the well. As a result of this exposure, the depth measurement accuracy of traditional coiled tubing counters is compromised. In the shallow gas market of the Western Canadian Sedimentary Basin, the error in depth measurements associated with coiled tubing velocity strings has been found to be significant and around 6 metres. Depth confirmation is typically then carried out using slickline. As a result of the error in depth measurement and the additional depth confirmation activity during the installation of the velocity string, the overall job time, the cost of operations and exposure of personnel at the wellsite are significantly increased.

Select Energy Systems, Inc in partnership with Count-Rite Oilfield Services, Inc., has developed a length measurement tool for coiled tubing, the SelectRite coiled tubing counter. The SelectRite CT counter is installed below the injector, and field tests have shown that it eliminates the limitations of traditional coiled tubing counters highlighted previously. Data transfer from the counter to the electronic display is wireless.

Currently, four operators in Western Canada will not land their velocity strings without using Select Energy's coiled tubing counter. For all these operators, accurate surface depth measurements have been achieved using the counter, thereby eliminating the requirement for additional depth confirmation and related personnel on the jobs.

This paper discusses Select Energy's coiled tubing counter which is designed for use with CT outside diameters (OD) of 19.05 mm to 50.8 mm and is currently being used mainly for coiled tubing completions operations in Western Canada.
Quick-Rigup HWU Barge-Assist Operations in the Gulf of Thailand
Authors: Robichaux Dicky , Henning Keith
Published: April 2008

This paper describes the results obtained and the equipment and techniques used in setting up the first barge-assisted hydraulic workover operation in the Gulf of Thailand (GOT). This paper will discuss the hydraulic workover unit (HWU) selected to perform the operations along with the engineering modifications that were required to meet the operator's requirements in the GOT, primarily installing electrical submersible pump (ESP) completions in depleting wells.

The paper includes descriptions of the challenges faced in operating an HWU on minimum facility production installations (MFPI) with total platform weight limitations of 40 mT and minimal crane capacity. Also discussed are a number of innovations designed and built into the HWU to enable a safe, quick assembly using a barge crane and remote power and fluid systems to make the HWU system as flexible as possible to cover all known deviations from the standard scope of work.

Lessons learned from the operations are also presented to demonstrate the ongoing operational challenges, the solutions implemented, and the results achieved.