Workover Operation Research Articles

Network-gel strength relationship and performance improvement of polyacrylamide hydrogel using nano-silica; with regards to application in oil wells conditions

Today, hydrogel plugs as a new and effective technology are widely used for temporary oil and gas well plugging. Although, the strength and fluidity of the hydrogels in the oil wells conditions are still most important challenges in their applications in workover operation. In this study, silica nanoparticles were used to improve the network characteristics and strength of hydrogels in addition to reduce the viscosity. It was found that network parameter can be introduced as an effective method for finding the optimum concentration of silica nanoparticles; by application of this method, rheology study is not necessary. The bottle and rheological tests were used to determine the hydrogel strength in desired oil well conditions (high temperature and high salinity). The SEM image of hydrogels showed that the homogenous three-dimensional filler network is formed. The results showed that using 9 wt% of silica nanoparticles decreased the molecular weight between two ties points in network structure in comparison to the neat hydrogels; it also increased the cross-link density of hydrogels (the number of tie points between each entanglement) more than 20 tie points. One of the main findings in this study was considerable increment of strength of hydrogel from 521 Pa to about 26,200 Pa (5000% increasing) that was not reported in other studies. Swelling behavior was also studied in various conditions such as distilled, formation, and tap water and oil solution. Increasing the strength has significantly reduced the hydrogel swelling in the aqueous solution. Based on the results obtained in this study, a polymer hydrogel containing 9 wt% of silica nanoparticles with relatively strong structural strength and thermal stability at 90 °C was proposed for field studies.

Review on the Evaluation of Casing Damage Level in Oil and Gas Field

The casing damage is a common problem encountered in the oil and gas field, and the casing damage will cause huge losses to the economic benefits of the oil and gas field. Grading the damage degree of the casing damage well can provide theoretical support for the oilfield workover operation and save the cost of workover. The casing damage classification has a strong guiding significance for the economic evaluation of the casing damage repair and the development of appropriate workover technology. After a review research on domestic and foreigner papers on the study of casing damage classification, it can be found that there is no mature theory and method for casing damage classification. After analyzing the entire workover process, the concept of the damage repair evaluation expert system is proposed to complete the entire workover process, evaluate the cost, and help the oil and gas field to obtain the best benefits.

Optimization of Oil Production by Gas Lift Macaroni in “X” Field

The background of this research was that in X Field many gas wells have stopped flowing years ago and not economical production anymore. Therefore the company has decided to use gas lift which is proper to the sandy oil reservoir characteristic. The tubing of the well has no gas lift mandrel completion as the well was a gas producer. The objectives of this research was that to design gas lift macaroni (GLM) to optimize oil production rate. The design of this research was that the new slim tubing 1.315 inch, called as macaroni tubing, was installed inside the existing 3. 5inch tubing. The gas lift valves are installed inside macaroni tubing. The data collection consists of reservoir data, surface data, and well diagram.The result of this research was that the gas lift macaroni installation can generate oil production rate of 425 STB/day of the three wells. Gas lift valves of well A is four valves, well B is five valves, and well C is three valves. The deviation of software and manual calculation of valves depth is less than 1%. The cost saving by installing gas lift macaroni instead of workover operation to change the existing tubing with new tubing equipped with gas lift valves is USD 5,620,955 of three wells.

Integrated Cemented Inflow-Control-Device System Design

This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper SPE 183383, “Integrated Off-Bottom Cemented Inflow-Control-Device System Design Toward Well-Delivery Optimization,” by Mohammed A. Al Madan and Mazen Bu Khamseen, Saudi Aramco, and Hedy Suherdiana and Ahmad Al Abdulmohsen, Baker Hughes, a GE company, prepared for the 2016 Abu Dhabi International Petroleum Exhibition and Conference, Abu Dhabi, 7–10 November. The paper has not been peer reviewed. Off-bottom-cementing (OBC) operations are unique to Saudi Arabia and represent a very challenging approach to drilling and workover operations when deployed in combination with inflow-control devices (ICDs) across horizontal sections. The multitasking-valve (MTV) feature in upgraded ICDs offers safe, simple, and cost-effective deployment operations. This paper discusses the first deployment of an ICD system combined with an OBC system for a workover operation in a mature producer well in the Kingdom of Saudi Arabia. Introduction In wells where an OBC liner is required to cover nontargeted formations above the production zone, two methods of deployment can be used: the one-trip system and the two-trip system. These refer, respectively, to whether the OBC components are deployed in a single trip along with the ICD or in a second trip with string in the previously deployed ICD completion. The one-trip OBC ICD completion does not allow an inner-string application. Therefore, circulation while running in hole was ineffective in this producer, which caused deployment problems. The two-trip OBC ICD completion was then considered. The idea was to split the completion into a lower ICD completion, which is dropped off inside the openhole horizontal section with a setting sleeve. The earlier two-trip OBC ICD completion used an inner string, a circulating system, and an openhole-packer-setting tool. This allowed 100% circulation from the shoe during deployment of the lower ICD completion, although circulation rate is limited because of pumping through the small internal diameter (ID). The upgraded ICD with an MTV allows the lower completion to be deployed without an inner string while achieving 100% circulation at the shoe, which smooths operations and saves up to 24 hours of rig time. The MTV temporarily blocks the communication between string and annulus while running in hole. Once reaching the setting depth, MTVs are actuated by hydraulic pressure. All hydraulically set equipment can also be set at this point. Ultimately, in the case outlined in the complete paper, it was decided to combine once again the separated deployment into a single system by use of the MTV feature, which provides important functions for the one-trip OBC ICD completion—the ability to perform 100% circulation from the shoe and to set all hydraulic downhole tools with one setting ball.

Mathematical Modelling of Silica Scaling Deposition in Geothermal Wells

Silica scaling is widely encountered in geothermal wells in which produce two-phase geothermal fluid. Silica scaling could be formed due to chemical reacting by mixing a geothermal fluid with other geothermal fluid in different compositions, or also can be caused by changes in fluid properties due to changes pressure and temperature. One of method to overcome silica scaling which is occurred around geothermal well is by workover operation. Modelling of silica deposition in porous medium has been modeled in previously. However, the growth of silica scaling deposition in geothermal wells has never been modeled. Modelling of silica deposition through geothermal is important aspects to determine depth of silica scaling growth and best placing for workover device to clean silica scaling. This study is attempted to develop mathematical models for predicting silica scaling through geothermal wells. The mathematical model is developed by integrating the solubility-temperature correlation and two-phase pressure drop coupled wellbore fluid temperature correlation in a production well. The coupled model of two-phase pressure drop and wellbore fluid temperature correlation which is used in this paper is Hasan-Kabir correlation. This modelling is divided into two categories: single and two phase fluid model. Modelling of silica deposition is constrained in temperature distribution effect through geothermal wells by solubility correlation for silica. The results of this study are visualizing the growth of silica scaling thickness through geothermal wells in each segment of depth. Sensitivity analysis is applied in several parameters, such as: bottom-hole pressure, temperature, and silica concentrations. Temperature is most impact factor for silica scaling through geothermal wellbore and depth of flash point. In flash point, silica scaling thickness has reached maximum because reducing of mole in liquid portion.

Thermal Effects on Subsea-Wellhead Fatigue During Workover Operations

This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper SPE 180065, “Thermal Effects on Subsea Wellhead Fatigue During Workover Operations,” by L. Cantinelli Sevillano, J. De Andrade, S. Sangesland, and M. Stanko, Norwegian University of Science and Technology, prepared for the 2016 SPE Bergen One Day Seminar, Bergen, Norway, 20 April. The paper has not been peer reviewed. Intervention and workover operations can significantly affect the structural integrity of subsea-wellhead systems with regard to their fatigue life. The increasing frequency of these operations has called for a renewed focus on the fatigue capacity of subsea wells, which has greatly improved the overall methodology used for wellhead-fatigue analysis. However, thermal effects along the well have yet to be incorporated. This paper analyzes wellhead-fatigue damage during a workover operation considering the thermal effects. Methodology The goal of the present study is to investigate the effects of the temperature variation along the well on wellhead-fatigue- damage rates by incorporating the temperature profiles of casing strings and cement into the fatigue-damage assessment of a particular wellhead system during a workover operation. In this study, a decoupled approach is proposed. The temperatures of riser, wellhead, and well components are calculated for different instants during the workover operation using a finite-difference method. Then, the temperature profiles for a given moment during the operation are incorporated into a 3D finite-element model (FEM) of the wellhead system. A structural analysis with focus on stresses at the fatigue hot spots is performed. Subsequently, a dynamic analysis of the riser provides the loading time history to which the wellhead is subjected; finally, combining the results of the structural analysis and the riser-response analysis enables the fatigue damage during the simulated operation to be estimated. The well adopted in this study follows a conventional subsea-completion program on the Norwegian continental shelf, with four casing strings and a production liner. Temperature Calculations. It is assumed that enough time has passed—between the shutting down of production and the moment that the workover riser is connected to the wellhead and the workover operation begins—for the temperature in the well to reach the undisturbed geothermal temperature profile. The workover operation simulated for temperature calculations consisted of injecting and circulating a heavy fluid until the hydrocarbons in the well were displaced. After that, circulation was stopped. The temperature profiles were calculated with a finite-difference method. During the simulated cold-fluid injection into the well, the deepest sections of the well are subjected to the largest temperature drop, given that the fluid is at lower temperature than the surrounding formation and well fluid, while the uppermost sections experience the effects of a circulating fluid at a higher temperature. Circulation was deemed to last approximately 3 hours.

Formation-Damage Diagnosis Facilitates Successful Remediation in Sandstone

This article, written by Special Publications Editor Adam Wilson, contains highlights of paper SPE 174279, “Formation-Damage Diagnosis Facilitates a Successful Remedial- Treatment Design and Execution in Sandstone Horizontal Oil Producer: A Laboratory and Field Case Study,” by M.A. Bataweel, SPE, A.H. Al-Ghamdi, SPE, P.I. Osode, SPE, T.A. Almubarak, SPE, E.S. Azizi, SPE, Eddy Sarhan, SPE, and M.G. Al-Faifi, SPE, Saudi Aramco, prepared for the 2015 SPE European Formation Damage Conference, Budapest, Hungary, 3–5 June. The paper has not been peer reviewed. Well-control fluids were used during a routine overbalanced workover operation in an offshore well completed in high-permeability sandstone. A fluid-loss-control pill was used to control excessive losses; however, because of the high permeability of the reservoir and the absence of sized particles in the pumped pill, a large amount of fluid was lost to the formation. A comprehensive review, accompanied by laboratory work, was conducted to identify the damaging mechanism and formulate a remedial treatment. Introduction Polymer-based fluids are beneficial in terms of generating viscosity to clean out the wellbore during any well intervention. Improper polymer selection has led to significant formation damage in several situations. Polymers also can invade the high-permeability zones, hampering hydrocarbon flow through the zones. Bipolymers generally are removed through acidizing, which breaks down the polymer backbone. The damage caused by polymers can be minimized with proper polymer selection. Standard remedial treatments for removing the near-wellbore polymer include injecting solvents (e.g., xylene), acids, alcohols, glycols, surfactants, or a mixture of these liquids into the well. In sandstone well treatments, formation composition should be considered carefully, especially minerals susceptible to acid attack. Three potential damaging mechanisms can occur during sandstone acidizing: formation deconsolidation in acid; reprecipitating during primary, secondary, and tertiary reactions; or the release of fines because of partial decomposition of minerals in acid. In the case of damage with oil-based material or emulsions, microemulsion treatments have been recommended. The microemulsion will solubilize the oil and emulsions and fluidize the filter cake into a single mesophase while dissolving the acid-soluble particles and making the solids and formation rock water-wet. The oil-based-mud particles in a filter cake will disperse, allowing the produced fluid to displace these blocking particles from the damaged zone into the wellbore and through any screens.

Mechanical Calculation for Workover String in Highly-Deviated and Horizontal Well

Force analysis and calculation of workover string in the highly-deviated and horizontal well is the basis of designing and checking string strength, selecting tools and determining operation parameters, which determines the operation safety and success of engineering accidence treatment. In this paper, by comprehensive consideration of wellbore structure, string assembly, string load and workover operation conditions, the workover string mechanical model has been built under three kinds of working states of lifting, lowering and rotating. The downhole string mechanics has been analyzed and calculated. By field verification, the string assembly, tool selection and operation parameter optimization can be achieved, which can improve the safety and success rates of workover engineering accident treatment.

Efficiency of Time Comparing with Modular Rigs for Workover Operation

In the past - 300ft Leg Jack-Up Rig predominantly used to Drill and Complete wells. In depleted phase currently, MH field is witnessing dominantly well work-over / repair scope to sustain production. Seabed inconsistencies caused by pug marks left by previous Jack-Up rigs and sea-bed pipe line network hinder Jack-Ups to approach platform and rework wells. Specificity of Jack-Up Rigs to approach Specific Platforms due to signature pug-marks left behind Increase in market demand for large Jack-Up rigs, increased day rates to very high levels. Above technical and economic compulsions drove decision making and acceptability to consider modular rigs over other alternatives. In order to ensure optimum performance of your rig, reduce downtime and maintain safety of your personnel, planned maintenance and accurate inspections are essential. Drilling's Rig Inspection Workshop (RIW) teaches the inspection and maintenance procedures required to ensure equipment integrity onland rigs, platform rigs and jack-up rigs. Candidates learn to implement the relevant standards and understand industry requirements so that they can verify the condition of a rig's equipment and improve safety, thus reducing the number of accidents and protecting the asset.

Potential of Corn Starch as Fluid Loss Control Agent in Drilling Mud

Fluid loss can be defined as the lost of mud filtrate into a porous permeable formation due to high hydrostatic pressure compared to the formation pressure. This phenomenon may cause some major problems to the workover operation such as formation damage, stuck pipe, and poor cementing job. Thus, in order to prevent fluid loss into formation, an environmentally safe, non-toxic, high biodegradability and low cost of polymer additive in drilling mud was prepared from corn starch as the fluid loss control agent. The purpose of this study is to investigate the potential of utilizing natural polymer-corn starch acting as fluid loss control agents in water-based drilling mud. The filtration and rheological properties of the water-based mud were analyzed at 170 to 200 °F temperature range with 0 to 10 g of corn starch concentration. Experimental results showed that the higher concentration of corn starch gave better fluid loss control behavior. Therefore, there is high potential of corn starch to be used as fluid loss control agent in drilling mud.

Workover String Mechanical Model and Calculation of Slanted and Horizontal Well

Force analysis and calculation of workover string in the slanted and horizontal well are the basis of designing and checking string strength, selecting tools and determining operation parameters, which determine the operation safety and success of engineering accidence treatment. In this paper, by comprehensive consideration of wellbore structure, string assembly, string load and workover operation conditions, the workover string mechanical model has been built under three kinds of working states of lifting, lowering and rotating. The downhole string mechanics has been analyzed and calculated. By field verification, the string assembly, tool selection and operation parameter optimization can be achieved, which can improve the safety and success rates of workover engineering accident treatment.

Optimal Well-Workover Scheduling by Use of Genetic Algorithms

This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper SPE 167818, ’Optimal Well-Workover Scheduling: Application of Intelligent-Well Control-Optimization Technology to Conventional Wells,’ by Faraj Zarei, SPE, Khafiz Muradov, SPE, and David Davies, SPE, Heriot-Watt University, prepared for the 2014 SPE Intelligent Energy Conference and Exhibition, Utrecht, the Netherlands, 1-3 April. The paper has not been peer reviewed. This study develops a workflow to design a proactive workover-optimization workflow by use of genetic algorithms (GAs). The work explored whether a “steered” GA, created by the addition of screening and advanced sampling methods to a “pure” GA, provides sufficient simplification of the problem to make it suitable for routine use in the field. Ultimately, a significant added field value was achieved by the “steered” GA when compared with the “pure” GA. Introduction The ultimate goal of field-development optimization is to maximize the objective function while reducing the uncertainty associated with the project value. Efficient reservoir-production planning requires a degree of well-control flexibility. Intelligent wells equipped with downhole flow-control devices and sensors inherently have a greatly increased flexibility to respond to (often unexpected) changes in the well and reservoir performance. Downhole inflow-control valves (ICVs) are used to control the well zonal flow rates. These valves are available in open/close, multiple-position-discrete, or infinitely-variable-position types. The completion design team is tasked with selecting an appropriate valve type according to the selected production scenario. Model uncertainties and difficulties in finding the optimal ICV control strategy for a dynamic reservoir model often result in the application of reactive control when operating the ICVs, despite the fact that a proactive strategy potentially delivers the highest added value during the field’s life. A workover operation is often required during the well’s operational life to address well-integrity and flow-assurance problems. The only option available for a conventional well to provide a level of well- and reservoir-management flexibility similar to that achieved by an intelligent well is to carry out an additional type of workover operation (i.e., one that is aimed at improving the well and/or reservoir performance). These are normally carried out as a reaction to observed changes in the well performance. Addressing such problems in a reactive mode carries the risk that the improvement in the well’s performance may not be apparent in the short term or may involve a long-term recovery loss caused by water or gas coning or inefficient reservoir sweep. Field-workover screening algorithms have been proposed to identify the workovers with the highest added value, but it is clear that a reliable and effective tool able to screen and explore the large search space of the potential workovers and that adds value to the reservoir-management process is not currently available. The search will need to consider the overall performance of the field throughout a specified period while respecting all operational limitations, as well as taking into account the risks and costs of the intervention. The nature of a workover operation in an interval resembles having an imaginary open/close ICV installed across the interval. This study uses a GA optimization search procedure—one of the most commonly used algorithms in proactive optimization of intelligent wells—to find optimal control strategies by considering both the well and field scale to assign workovers optimally at the full-field level.

Study on Load Capacity of Anchor Piles for Oil Workover Derrick

the workover rig is always fixed by anchor piles in land oilfields. Good load capacity of anchor pile is the key factor to the guarantee of safe workover operation. The load capacity test of anchor pile is complete by connecting vibration test and method of mechanical impedance. The reduction coefficient must be used in calculating the anti-pulling load capacity because of difference of soil kinds. To testify the results from mechanical impedance method, the system of pulling pile directly is built. The average error of data from this system is within 5%. It can conclude that the method of mechanical impedance and vibration test can be popularized widely to load capacity of anchor pile, especially in different kinds of soil. The research can enrich the theories of uniform section pile and give the theoretical foundation to fix the anchor piles safely during workover rig operations.

The Kinetics Mechanism Analysis of Sulfur Depositions in High Sulfur Content Gas Reservoirs

The origin of particles which lead to reservoir damage in oil industry mainly includes internal generation and external invasion. The particles generated in reservoir include clays, mineral particles, deposits and particles which are separated out in physical and chemical effects. Particles of external invasion include invasions in the process of drillings and fracturing operations, particles in work-over operation and completion fluid operation, or debris which are carried by injection fluid (water, chemicals, etc.). The force of the particles has affected the seepage law in high sulfur gas reservoir. By analysis of the particle migration, sedimentary characteristics, and the force situation of sulfur particles, we will discuss dynamical mechanisms of sulfur deposition.

Evaluation of operational performance of workover rigs activities in oilfields

Purpose – This paper aims to develop a practical method to evaluate operational performance of workover rigs and present an approach to measure the overall equipment effectiveness (OEE) based on results of the evaluation method.Design/methodology/approach – The area of this study focuses on workover rigs processes in the oilfield and investigates the impact of workover activities on the production at the Sarir Oilfield in Libya. The loss of time from workover procedures and electrical submersible pumps ESP installation and pulling, which affect oil well production, should be eliminated in order to reduce the cost. Several example calculations of workover operation efficiency involving actual workover operational data are presented. The method of evaluation of workover process has been developing which were the bases of OEE calculation.Findings – The measure was developed to help support continuing efforts around process improvements and cost leadership at Oilfields. The results on the empirical findings a...

Design Scheme for New Workover Mechanical System

In workover operation, conventional way makes the process complex, labor intensity high and operating environment hostile. For solving the problem, the new scheme for workover mechanical system was put forward. Hanger was removed in the system. We can execute tube movement with macro/micro mechanical arm and achieve sending down and lifting pipe with supporting mechanical hands. It is designed for the first time in china.

The Killing Method of Exceptional Operating Conditions Well

During the process of drilling, overflow happens when the waterhole blocks, drilling tool breaks off and drops into the well, or empty hole occurs after hoisting completed. In course of the workover operation, overflow happens while oil tube fracturing, blocking up, and occurring empty well or can’t flow. As it is difficult to establish effective fluid cycling for such type of well when overflow occurs, conventional killing well method cannot handle the problem of overflow for the well in special operating conditions. The so-called special operating conditions well have intact well head control equipment, but unable establish cycling after the overflow well shut in. The paper is aimed at finding out the non-routine well control procedure to deal with the overflow of the well in special operating conditions. Study the well killing technology in four situations. The situation included the well is full of natural gas, lower of the well is liquid column and upper of the well is natural gas, the wellbore blocks and unable establish cycling for containing liquid column, besides the wellbore holds fish where the fish is intact and doesn’t block the wellbore, the fish blocks the wellbore or the fish is breakup and blocks the wellbore. Discuss the principles, steps, calculation procedure and formulas of killing well in volumetric control mode. The result is applied in one of the non-conventional wells’ workover operation in the eastern of Sichuan. This paper simulates the calculation of killing well and reveals the killing well curves and form design.

Study on Hoist Force Calculation of Hydraulic Lifting System Used in Pressure Balance Workover Rig

Abstract. Pressure balance workover is an advanced downhole operation technique. It can hoist the strings of the tube or put it down under certain pressure. The research on pressure balance workover rig has become a hotspot in both domestic and overseas. Pressure balance workover operation technique has been widely used oversea. At the present time, relevant studies have been developed in China. In this paper, domestic and international technology status is fully analyzed, working principle of hydraulic lifting system is studied, then equivalent calculation model and calculation method of hoist force are put forward, calculation program of hoist force was compiled for the different oil pipe depth, curve and charts changing with the oil pipe depth are given, It provides a theory reference to field operation.

The CO2CRC Otway Project: Overcoming challenges from planning to execution of Australia’s first CCS project

The aim of the CO2CRC Otway Project (Otway) is to demonstrate that carbon capture and storage (CCS) is a viable option for CO2 mitigation under Australian conditions. The Otway Project is Australia’s first demonstration project and is well underway with injection having started in April 2008 and over 23,000 tonnes of CO2 injected by the end of September. Project activities commenced in late 2004 and being the first, faced significant regulatory and execution challenges. In 2005, the emphasis was on feasibility and project development. Following a rigorous technical and consultative approach, the project regulatory permitting process was defined, the site characterisation and risk assessment started and the field implementation organization defined. In 2006 the project focused on reducing the uncertainties and following Front End Engineering Development (FEED) process as part of seeking approval for major expenses. Several technical challenges were faced and dealt with in finalising the new injection well location and the plant design. The monitoring and verification plan was defined and data acquisition for the pre-injection atmospheric, soil gas and water chemistry characteristics started. In 2007, the project entered the execution phase with the successful drilling of a new injection well. A rich data set of cores and logs was collected enhancing the reservoir model and dynamic simulations. Monitoring activities continued and a 3D surfaceseismic and vertical seismic profile (VSP) acquired concurrently to define the pre injection baseline. Through a complex workover operation, the observation well was equipped with an integrated geophysical and geochemical sensor assembly to facilitate collecting monitoring data during injection. Surface installations, such as the process plant and the pipeline were constructed and the system commissioned in readiness to commence injection. At each stage the project faced several non-technical and technical challenges. In overcoming these, valuable insights have been gained and lessons learnt. These have been incorporated in the proposed Australian legislation on CCS and planning for future projects. To date the project has been positively received by the community. Injection has commenced and supported by a rigorous monitoring and modeling program, is well on its way towards gaining public acceptance for CCS under Australian conditions, through a comprehensive community consultation program and safe and successful operations.

Development of a Downhole Separator and Intensifier for Coiled Tubing Jetting

Abstract Wells often build scale deposits on the inside of their tubulars that can impede production or interfere with a workover operation. When this scale buildup is over long intervals, coiled tubing (CT) is often the conveyance system used to deliver acid, drilling or jetting technologies to remove the scale. Acidizing through coil can be effective only if the scale is acid soluble and it can be expensive. Drilling with motors can be very effective, but motors are susceptible to performance issues, especially if high nitrogen ratios are required. Jetting the scale is possible, but this technology also faces challenges. Delivering sufficient downhole hydraulic pressure to overcome the scale's threshold pressure is very difficult due to the limited pressure capacity of CT and frictional pressure losses in long CT strings. Further, if nitrogen is required to ensure returns, the gas phase quickly disperses the fluid jet as it exits the jetting tool, and very little power is delivered to the scale face. Recent technical advances in CT jetting technology include a rotary separator to separate the nitrogen from the fluid and a downhole pressure intensifier to take the separated water and increase the hydraulic pressure delivered to the jetting tool. The paper first discusses measurements of the threshold pressure required for removal of oilfield scales. The development of a gas separator and downhole intensifier are discussed next, followed by the results of testing these tools. Introduction Mineral scale deposits inside of production tubing can reduce production or interfere with workover operations. Coiled tubing is used to remove this scale using motors or jetting tools. Jet milling of scale is an attractive option because fluid jets will not damage tubulars or other downhole equipment. Jet milling capabilities are limited by the threshold pressure required to initiate milling and by fluid jet dissipation. The jet pressure delivered to the scale surface determines the ability of the jet to cut a given scale. The jet power then determines the rate at which the scale can be removed. The pressure that can be delivered to a jetting tool through CT is limited by fatigue limits of the coil and the pressure capabilities of available pumps. The jet power, which determines milling rates, is further limited by friction pressure loss in the CT. These losses become more significant in deep wells. One approach to cutting scale at the pressure available using coil is to add abrasives(1), however, this approach adds cost and complexity to the operation. Another approach is to boost the pressure of the jets with a downhole intensifier. In the 1990s, the FlowDril Corporation manufactured a large-scale downhole intensifier pump to drill 77/8 in to 83/4 in holes with jet assisted roller cone bits(2). The unit was designed to work with a conventional rotary drill string and run on drilling mud. The intensifier ratio was 14:1, delivering 84 l/min at 200 MPa from mud supplied at 1,260 l/min and 23 MPa. A similar approach would allow CT pressure to be boosted to a level capable of milling hard scale. The effectiveness of fluid jetting tools is further limited by dissipation of the jet in the high pressure well environment. Submerged, non-cavitating fluid jets are subject to rapid dissipation due to turbulent mixing of the fluid. The maximum length of the high pressure jet core produced by an ideal jet under these conditions is under seven nozzle diameters(3). Intense turbulence persists to a range of around 20 nozzle diameters. By contrast, water jets in air can be effective at ranges of over 1,000 nozzle diameters. Jet dissipation effects