A set of 5 wells were to be drilled with directional Coiled Tubing Drilling (CTD) on the North Slope of Alaska. The particular challenges of these wells were the fact that the desired laterals were targeted to be at least 6000ft long, at a shallow depth. Almost twice the length of laterals that are regularly drilled at deeper depths. The shallow depth meant that 2 of the 5 wells involved a casing exit through 3 casings which had never been attempted before. After drilling, the wells were completed with a slotted liner, run on coiled tubing. This required a very smooth and straight wellbore so that the liner could be run as far as the lateral had been drilled. Various methods were considered to increase lateral reach, including, running an extended reach tool, using friction reducer, increasing the coiled tubing size and using a drilling Bottom Hole Assembly (BHA) that could drill a very straight well path. All of these options were modelled with tubing forces software, and their relative effectiveness was evaluated. The drilling field results easily exceeded the minimum requirements for success. This project demonstrated record breaking lateral lengths, a record length of liner run on coiled tubing in a single run, and a triple casing exit. The data gained from this project can be used to fine-tune the modelling for future work of a similar nature.

Cleanouts and milling make up most of the common coiled tubing (CT) operations around the globe. The objective of each is to remove debris from a wellbore, such as sand, scale, cement, or fracture plugs, to promote an unobstructed flow path for fluids. For decades, operators and service companies have focused heavily on methods to optimize removal of debris through the development of specialized tools, fluids, techniques, and predictive models. These are coupled with wellsite equipment digital acquisition systems to capture CT behavior, pump rates, and chemical additive rates; very little attention has been given to the rates of the fluid and solids being returned to surface. The composition and quality of fluids being pumped into the well are often well characterized, and the pump rate is recorded digitally to the second. By contrast, information on the fluid being returned is frequently limited to intermittent, manual surveys of the flowback tank fluid level that often go unrecorded. Fluid samples are rarely analyzed, even by inexact measurements, to provide feedback to the predictive model. This results in a missed opportunity to optimize the operation as well as to recognize and respond to undesirable trends and actions in real time. This paper describes a simple digital acquisition system developed and implemented in the field to digitally record, plot, and monitor critical wellsite parameters including flowback rate, solids returns, annular velocities, and downhole Reynolds numbers. The system provides a real-time visual aid to observe the direct impact that operational decisions have on cleanout efficiency and the opportunity to correct and optimize the cleanout operation. Furthermore, the system offers the opportunity to rapidly recognize and respond to unexpected trends such as a gradual or sudden loss in return rate or a decrease of solids returns which could rapidly result in serious consequences such as a stuck-pipe situation.

Completions operations, especially in modern day extended laterals, presents challenges related to tripping to total depth, applying weight down and pull up, and rotating. As dozens of stages in laterals exceeding 10,000 ft stepout have become frequent, numerous technologies have risen to assist with pushing the envelope for reliable completions operations in these long laterals. This paper examines a combination of three technologies that are more commonly being applied when drilling out frac plugs in long horizontals in the USA: hydraulic completion units, torque and drag software, and data acquisition systems. Coiled tubing units (CTU) have historically been used to drill out frac plugs in shorter horizontal shale wells for the last two decades, and where coil has mechanical limitations, Hydraulic Completion Units (HCU) have taken over drilling out frac plugs in the longer laterals of >10,000 ft. As the limits of drilling out frac plugs have been tested for HCUs, accurate real time data has enabled the crews to make the most of their equipment to reliably complete wells with longer and longer lateral sections. Torque and drag software modeling is a tool commonly used to predict axial force and torsional values during completions that result in the available hook load and the rotary torque requirements. The largest unknown in the planning phase is the appropriate friction factor to use for the upcoming well, with accurate friction factor prediction therefore the key to accurate prejob analysis. As of 2019 remote telemetry data acquisition systems (DAS) have been used on the HCUs, which has allowed key performance indicators (KPIs) to be automatically calculated. The program provides live feed to the service company and operator so that real time changes can be made if necessary. In addition to tracking KPIs in real time to provide the field crew positive or negative feedback, friction factors can be matched to predictive torque plots to identify trends prior to problems arising. Post-job analysis is needed to produce accurate predictive friction factors for future offset wells. The two main components to a successful post-job analysis are a software model that correctly represents the prior wellbore operations and accurate field data to compare with that model. Unfortunately, the software models in use are commonly limited by necessary assumptions with input data, such as rotary speed and tripping speed, and field data collected for comparison is often rudimentary. Experienced field personnel using engineering best practices can make use of current tools in combination to overcome the limitations commonly inhibiting accurate performance planning and predictive modeling. The inclusion of the DAS present on the HCU has greatly enhanced the accuracy and amount of rig data gathered, which can then be used in conjunction with operational procedures and torque and drag software to accurately plan and execute completions operations in the wellbore. Using data acquisition software, a constant stream of data was collected in one-second intervals in over two dozen wells. This system has the ability to measure both rotary speed and rotary torque, which are critical parameters when drilling out frac plugs. By removing these assumptions in the post-job analysis over a number of wells, a range of friction factors have been established for the Appalachian Basin in the Utica and Marcellus plays. The authors will present field data from two wells as representative case studies, along with the range of predictive friction factors established from 13 wells for the particular completions operations evaluated in the Permian and Appalachia plays. It is the goal of the authors to disseminate technical information on the methodology and practice of modeling wells post-job, calibrating friction factors, and establishing predictive ranges for successful use in future projects.

Production decline caused by sand ingress was observed on 2 offshore oil wells in Brunei waters. Both wells were completed with a sub-horizontal openhole gravel pack and were subsequently shut in as the produced sand would likely cause damage to the surface facilities. In an offshore environment with limited workspace, crane capacity and wells with low reservoir pressures, it was decided to intervene the wells using a catenary coiled tubing (CT) vessel. The intervention required was to clean out the sand build up in the wells and install thru-tubing (TT) sand screens along the entire gravel packed screen section. Nitrified clean out was necessary due to low reservoir pressures while using a specialized jetting nozzle to optimize turbulence and lift along the deviated section. In addition, a knockout pot was utilized to filter and accommodate the large quantity of sand returned. The long sections of screens required could not be accommodated inside the PCE stack resulting in the need for the operation to be conducted as an open hole deployment using nippleless plug and fluid weight as well control barrier. A portable modular crane was also installed to assist the deployment of long screen sections prior to RIH with CT. Further challenges that needed to be addressed were the emergency measures. As the operation was to be conducted using the catenary system, the requirement for an emergency disconnect between the vessel and platform during the long cleanout operations and open hole deployment needed to be considered as a necessary contingency. Additional shear seal BOPs, and emergency deployment bars were also prepared to ensure that the operation could be conducted safely and successfully.

In a deviated well in Caspian Sea gas oil ratio (GOR) increased rapidly in 2017. The result was an oil rate decline with several choke backs to manage GOR build-up. After performing two production-logging jobs, it was confirm that 76% of the gas production was coming from four upper perforations. The main objective was to perform a Gas Shut off (GSO) treatment in two stages to reduce gas production by squeezing polymer into the formation and setting packers at 59° deviation inside 9-5/8 in. casing for temporarily isolation of middle and lower production sands. Fifteen runs were perform with a tube wire-enabled CT telemetry (CTT) system which consists of a customized bottomhole assembly (BHA) that instantaneously transmits differential pressure, temperature, depth data to surface through a non-intrusive tube wire installed inside the CT. For the first time in the region, a tension, compression and torque (TCT) sub-assembly was deploy to control the entire set/retrieve process with accurate downhole upward/downward forces. CTT technology was a key element to successfully set two Thru Tubing Inflatable Retrievable Packers (TTIRP) by doing casing collar locator (CCL) correlations at tubing end which was 133 m and 228 m (MD) shallower from setting depths. In addition, during second GSO operation, polymer crosslink time was modify based on actual bottomhole temperature recorded with CTT system. Finally, during third GSO treatment placement was improve spotting more GSO system in casing section avoiding further treatments. After successful placement of the GSO system, a drop from 15.5 to 4.5 MMscf/day in gas production was observed along with GOR reduction from 11,000 to 750 MMscf/bbl and oil rate increment from 1.4 to 6.04 Mbpd. Furthermore, after gas reduction operator was able to produce between 1.5 to 2.0 Mbpd from other wells that were choke back based on gas handling capabilities limitations The novelty of using the CTT system and TCT sub-assembly for real-time monitoring of BHA data was proven for not only positioning two TTIRP, modifying polymers crosslink design, placing polymer precisely across target intervals and retrieve two TTIRP that at the end provide direct and positive financial impact for the operator.

Traditional intervention operations with coiled tubing (CT) in extended reach horizontal wells might be difficult to access due to lockup from frictional forces and operational inefficiencies. Using conventional shifting tools requires multiple runs to shift open and close multiple sliding sleeve doors (SSD). This paper is a case study of an electric-line powered shifting intervention operation to shift open an SSD, circulate fluids though the sleeve and into the annulus, and then close and repeat this for another SSD in a long horizontal well—all in a single run. The paper discusses the different methods that can be used to efficiently seek and latch onto the shifting profiles using a tractor, wireline cable, and the shifting tool itself with an inchworm motion. The electric-line shifting tool monitored and verified the opening and closing of the sleeves in real time using its onboard sensors. These techniques were effectively deployed in multiple wells that required the annulus to be displaced with fluid after running smart completions. The completions were installed in the well with the SSDs in a closed position, and the shifting intervention consisted in opening the SSD, pumping fluids through the sleeve, and closing the SSD. The tool was anchored in place in the wellbore during the entire circulating operation, and the SSD was subsequently closed. This operation was then repeated on the second SSD in the wellbore, and the entire operation was completed in a single run. Also, no additional caliper run was needed as the shifting tool verified the position of the SSDs. These methods were used in a long horizontal well with the help of real-time measurements. The tool measurements identified if the SSDs were in open or closed position or anywhere in-between. The shifting tool provided confirmation via its measurements that the sleeve was not partially open. This was particularly important when pumping fluid through the annulus to achieve the maximum flow through the sleeve. Operating using electric-line was extremely efficient and eliminated the need to perform multiple runs, thus achieving time savings on the rig. This is the first time that a paper discusses the different seek methods that can be used for carrying out a electric-line mechanical intervention operation. It represents a novel method using a shifting tool as a caliper to probe and measure the completion inner diameter changes while seeking for the profile. It provides a valuable method for reliably and confidently locating and latching onto a shifting profile. Finally, this is the first time that a paper correlates the theoretical mechanics of shifting a sliding sleeve with consistent results from system integration tests and downhole measurements from the real job.

As the boundaries are pushed with increased length of horizontal wells, coiled tubing (CT) well intervention capabilities are challenged requiring new technologies to expand existing capabilities. When utilizing coiled tubing, standard best practice is to first utilize CT modeling software to optimize CT size and weight for maximum reach. After choosing the right CT size, the next and most critical factor to address in extending the reach is, drag and frictional forces between the CT and the wellbore. Reducing friction and delaying helical buckling will significantly increase the reach. Several versions have been created utilizing various pressure pulse tools in the CT bottom hole assemble (BHA) to accomplish this task. These tools work by creating vibration or pressure pulses that allow for a delay in the onset of the helical buckling of CT and are widely utilized and accepted as solutions. However, existing agitation tool limitations have been reached. A newly designed and developed, hydraulically driven agitation tool (HDAT) to extend CT reach delivers continuous frequency pressure waves along the entire length of the CT. The HDAT provides a reduction in static friction and converts that to a dynamic friction form along the CT string. The continuous hydraulic agitation reduces the onset of helical buckling and thus reduces CT helical contact points, resulting in lower resistance force. The development, design, and lab testing for the HDAT has been through extensive development stages resulting in three generations of the tool, with each version providing an incrementally improved performance. The latest generation HDAT has been designed to function at optimum operational frequencies and produce excitation that works on a longer section of the CT. The performance advancement of the newly designed HDAT generation was achieved after extensive lab testing with a field run reaching a total depth of 24,500 ft over a 4,600 ft open hole lateral section. The new HDAT was redesigned to improve performance and reliability to achieve an effective matrix acid stimulation treatment. The lessons learned from previous generations were imbedded to extend the reach of the CT in the most challenging extended reach wells.

A large collection of data recorded during coiled tubing (CT) operations has been analyzed using proprietary pattern recognition algorithms to identify downhole events with a high degree of confidence. These events include the drilling of plugs and stuck pipe incidents. Key performance indicator (KPI) metrics derived from this analysis provide insight into industry trends over time and by region, and can provide useful performance benchmarks for service providers and operator companies. Depth, weight and pressure data from multiple sources has been streamed and stored on a shared platform over a five year period, creating a record of over 39,000 data files. This data was processed to generate KPI-type statistics for over 500,000 detected plugs and 760 possible stuck pipe scenarios, based on analysis of depth and weight signatures. Using surface measurements to quantify downhole events has some limitations, but the method has proven sufficiently robust to allow useful trends to be observed and evaluated. While the analysis is confidential to the parties involved, a contributing company can compare their ‘performance’ statistics (as evaluated by the third party algorithms) against averages representative of the industry at large, arranged by year and geographic region, to identify areas of relative strength or weakness. An operator company can likewise compare metrics for different service providers (derived solely from jobs performed for their company) for those which elect to share data in this fashion. This paper presents statistics for plug drilling operations and stuck pipe incidents in North America between 2016-2020, a period of significant change in the CT industry. Examples show how average plug drilling times have generally decreased, with less frequent use of short trips and fewer pipe cycles. The data shows that, for some companies, faster operations have come at the expense of more frequent or severe stuck pipe incidents, whereas other companies have experienced fewer such problems. This comparative analysis illustrates how downhole outcomes can be deduced from surface measurements, and resulting performance metrics can vary widely between companies, fields and geographic regions.

A new coiled tubing (CT) failure mechanism has appeared in the past two to three years. The failures occur in CT strings used for frac plug milling in extend reach horizontal wells. The objective of this paper is to investigate a possible cause for these failures. The primary emphasis is analyzing the dynamic response of the CT to axial vibrations induced by a downhole extended reach tool [1], and the resulting tubing material response leading to failure.

On the Norwegian continental shelf (NCS), coiled tubing (CT) cleanout requires small bites and frequent wiper trips to the surface due to potential sand bedding in a large and deviated completion. A real-time CT downhole measurement system is used to optimize the operation, following a dynamic workflow. Conventionally, the system is powered by downhole lithium battery, which limits CT downhole operating time. A continuous surface-powered system was needed to promote further optimization for such operation. A new hybrid electro-optical cable was introduced to enable continuous power supply from surface to the real-time downhole tool sensors. The system consists of a surface power module that sends power through a layer of low-DC-resistance conductors and optical fibers that enable data telemetry. Conventionally, only three to four trips can be completed before replacement of the downhole battery is required. Battery replacement can take up to 8 hours due to the complexity of that offshore environment. With the continuous power supply, the CT cleanout operation can continue for days without interruption of data from the downhole tool sensors. A three-well CT cleanout campaign in the NCS demonstrated the benefits of this new real-time downhole measurement system by using accurate downhole weight and torque readings to control the penetration through scale and avoid motor stalls. Sections of scale bridges were identified during the cleanout by monitoring fluctuations of downhole torque of the mill. The monitoring allows CT operators to control penetration rate and bite length during the cleanout. When the milled debris are swept, downhole weight is used to detect early signs of solids plugging around the mill. Downhole pressures complement surveillance of the sweeping of solids to the surface by giving a qualitative measurement of solids loading through conversion of the real-time bottomhole pressure reading into equivalent circulating density with changing CT depth. The process of optimizing bite length and sweeping speed is repeated without interruption thanks to continuous power supply from the surface, eventually leading to time reduction. In one of the wells, downhole tools uninterruptedly acquired data for 10 days straight. The CT managed to clean out a total of 40 908 kg of a mixture of scale and sand, with an estimated average time reduction of 25% when compared to CT cleanout without real-time downhole data. Delivery of continuous high-voltage power to downhole tools not only enables reduction in operating time, it also paves the way for extending the capabilities of CT interventions by enabling the operation of more electrically activated application tools. It allows combining multiple work scopes in a single CT run, which reduces operating cost and provides greater operational flexibility. Finally, eliminating the dependency on lithium batteries reduces the carbon footprint for a more sustainable operation.

Coiled Tubing Drilling (CTD) has been growing and developed rapidly through the last two decades. There have been numerous highly successful applications of CTD technology in Alaska, Canada, Oman and the United Arab Emirates (Sharjah Sajaa and Dubai Murgham fields), among other places. Currently, Saudi Arabia has undertaken a campaign for the last seven years that has shown successful results in gas reservoirs. ADNOC initiated a trial Coiled Tubing Underbalanced Drilling (CTUBD) project in the onshore tight gas reservoirs in Abu Dhabi, United Arab Emirates beginning operations 1-December-2019. The initial trial will consist of three (3) wells. The purpose of the trial is to assess the suitability of CTUBD for drilling the reservoir sections of wells in these fields, and further application in others. The reason for choosing coiled tubing for drilling the reservoir sections is based upon the high H 2 S content of the reservoir fluids and the premise that HSE can be enhanced by using a closed drilling system rather than an open conventional system. The three wells will be newly drilled, cased and cemented down to top reservoir by a conventional rig. The rig will run the completion and Christmas tree before moving off and allowing the coiled tubing rig to move onto the well. The coiled tubing BOPs will be rigged up on top of the Christmas tree and a drilling BHA will be deployed through the completion to drill the reservoir lateral. The wells will be drilled underbalanced to aid reservoir performance and to allow hole cleaning with returns being taken up the coiled tubing / tubing annulus. The returns will be routed to a closed separation system with produced gas and condensate being primarily exported to the field plant via the production line, solids sparge to a closed tank or pit and the drilling fluid re-circulated. The primary drilling fluid will be treated water; however, nitrogen may be required for drilling future wells in the field and will be required regardless for purging gas from the surface equipment during operations. A flare will also be required for emergency use and for start-up of drilling. If the trial proves a success, a continuous drilling plan will be put in place.

During the completion phase of an unconventional well in Turkey, casing deformation represented a challenge to the operator and Coiled Tubing (CT) service provider due to the potential loss of almost 70% of the horizontal section. The deformation obstructed the path to continue the milling the remaining plugs. The implementation of bicentric mills and Multi-Cycling Circulation Valve (MCCV) incorporated in the milling assembly allowed efficient recovery of the horizontal section. The tubing condition analysis done by the engineering team showed that symmetric mills would not be beneficial. Conformance tubing was not an option. Bicentric milling approach was deemed the most viable solution. This approach consists of using offset mills where rotation causes the cutting head to cover an area larger than the mill's frontal face. However, this approach could lead the CT pipe getting stuck due to big junk left. The use of a MCCV, limiting the number of milled plugs, and performing a fishing run between milling runs were key to the success of the bicentric milling approach. The Turkish well was completed with ten stages isolated by nine aluminum plugs. During the fracturing of stage seven, an abnormal pressure drop was observed while keeping the same pump rate, indicating possible casing damage. After all the stages were fractured, the CT proceeded to mill the plugs using a 4.63-in Outside Diameter (OD) mill. After three plugs were milled, an obstruction was detected, indicated by frequent aggressive motor stalls at the same depth. A tapered mill was run to perform a tubing conformance, and after several hours of unsuccessful penetration, the tool was recovered. At the surface, the tool showed signs of wear around 4.268 in. A 4.0-in OD mill was used to drift this section, and it passed free. An analysis of both the plug anatomy and the casing condition was done to determine the most viable solution. A 4-in OD bicentric mill was designed to pass across the restriction with an adjusted eccentricity to allow higher contact area. Three bicentric milling runs were made with the limit of a maximum of two plugs per run to avoid a CT stuck situation due to the larger cuttings as a result of the mill's asymmetry. The sparsity of information on using bicentric mills for plug milling required research into unpublished practices for such scenarios. This paper documents bicentric milling approach, the use of offset mills, and the mitigation measurements taken during this project to avoid a stuck situation due to large debris generated.

Coiled tubing (CT) milling and cleanout interventions depend heavily on the circulation of fluids and debris throughout a wellbore. When these interventions are performed on lateral wells which are subhydrostatic or are not able to sustain a stable column of fluid during the operation, they pose unique challenges. This is mostly due to the inability of the well to support a column of fluid, which consequently causes circulation over long distances and along narrow annular spaces to be difficult or impossible, particularly when a thief zone is present. The many consequences of poor to nonexistent fluid circulation can be severe, ranging from poor hole cleaning and formation damage to inducing a stuck pipe scenario. Over the years, many mechanical and chemical solutions have been employed to improve fluid circulation in subhydrostatic wells, but each comes with its own set of challenges and can be costly to implement. Two methods commonly used today to improve debris removal from a low-pressure wellbore include the use of nitrogen and the creation of an underbalanced condition in the wellbore by flowing formation fluids. The former is expensive, time consuming, and requires advance bottomhole assembly (BHA) planning whereas the latter can lead to significant formation damage or a reduction in fracture conductivity through the removal of proppant from the near-wellbore area. A fiber- and particulate-laden degradable loss control system (LCS) is proposed as an improvement on the current techniques used to improve circulation in subhydrostatic wells. The LCS temporarily prevents losses to the reservoir and enables the circulation of debris out of the well. The system was applied to low-pressure wells in North America to demonstrate its effectiveness in addressing the reduction or loss of circulation throughout the wellbore and improving debris transport to surface.

Successful reservoir surveillance and production monitoring is a key component for effectively managing any field production strategy. For production logging in openhole horizontal extended reach wells (ERWs), the challenges are formidable and extensive; logging these extreme lengths in a cased hole would be difficult enough, but are considerably exaggerated in the openhole condition. A coiled tubing (CT) logging run in open hole must also contend with increased frictional forces, high dogleg severity, a quicker onset of helical buckling and early lockup. The challenge to effectively log these ERWs is further complicated by constraints in the completion where electrical submersible pumps (ESPs) are installed including a 2.4" bypass section. Although hydraulically powered coiled tubing tractors already existed, a slim CT tractor with real-time logging capabilities was not available in the market. In partnership with a specialist CT tractor manufacturer, a slim logging CT tractor was designed and built to meet the exceptional demands to pull the CT to target depth. The tractor is 100% hydraulically powered, with no electrical power allowing for uninterrupted logging during tractoring. The tractor is powered by the differential pressure from the bore of the CT to the wellbore, and is operated by a pre-set pump rate from surface. Developed to improve the low coverage in open hole ERW logging jobs, the tractor underwent extensive factory testing before being deployed to the field. The tractor was rigged up on location with the production logging tool and ran in hole. Once the coil tubing locked up, the tractor was activated and pulled the coil to cover over 90% of the open hole section delivering a pulling force of up to 3,200 lb. Real-time production logging was conducted simultaneously with the tractor activated, flowing and shut-in passes were completed to successfully capture the zonal inflow profile. Real-time logging with the tractor is logistically efficient and allows instantaneous decision making to repeat passes for improved data quality. The new slim logging tractor is the world's slimmest most compact, and the first of its kind CT tractor that enables production logging operations in horizontal extended reach open hole wells. The ability to successfully log these extended reach wells cannot be understated, reservoir simulations and management decisions can only as good as the quality of data available. Some of the advantages of drilling extended reach wells such as increased reservoir contact, reduced footprint and less wells drilled will be lost if sufficient reservoir surveillance cannot be achieved. To maximize the benefits of ERWs, creative solutions and innovative designs must continually be developed to push the boundaries further.

The accumulation of rock cuttings, proppant, and other solid debris in the wellbore due to inadequate cleanout remarkably impedes field operations. This article presents a new hole cleaning model, which calculates the Critical Transport Velocity (CTV) in conventional and fibrous fluids. The study is aimed to establish an accurate mechanistic model for optimizing wellbore cleanout in horizontal and inclined wells. The new CTV model is established to predict the initiation of bed particle movement during cleanout operations. The model is formulated considering the impact of fiber using a special drag coefficient (i.e. fiber drag coefficient), which represents the mechanical and hydrodynamic actions of suspended fiber particles and their network. The dominant forces acting on a single bed particle are considered to develop the model. Furthermore, to enhance the precision of the model, recently developed hydraulic correlations are employed to compute the average bed shear stress, which is required to determine the CTV. In horizontal and highly deviated wells, the wellbore geometry is often eccentric, resulting in the formation of flow stagnant zones that are difficult to clean. The bed shear stress in these zones is sensitive to the bed thickness. The existing wellbore cleanout models do not account for the variation in bed shear stress. Thus, their accuracy is limited when stagnant zones are formed. The new model addresses this problem by incorporating hydraulic correlations to account for bed shear stress variation with bed height. The accuracy of the new model is validated with published measurements and compared with the precision of an existing model. The use of fiber drag and bed shear stress correlations has improved model accuracy and aided in capturing the contribution of fiber in improving wellbore cleanout. As a result, for fibrous and conventional fluids, the predictions of the new model have demonstrated good agreement with experimental measurements and provided better predictions than the existing model. Model predictions show a noticeable reduction in fluid circulation rate due to the addition of a small quantity of fiber (0.04% w/w) in the fluid. In addition, results show that the existing model over predicts the cleaning performance of both conventional and fibrous fluids.

Among the many applications of Coiled Tubing (CT) services, milling plugs and wellbore sand cleanout are two of the major applications. The transport of solids to the surface, as well as monitoring the return rates, are two sources of information which can have a significant impact on the execution of these jobs. Traditionally the flowback crew communicates this information to the CT control cab upon request. However, by utilizing an acoustic monitor and ultrasonic flowmeter, it can reduce the dependence on flowback operators and provide real-time solid measurement and return flow rate. The acoustic monitor is a passive, non-intrusive device that is designed to measure the acoustic noise induced into the pipe wall as solids impact the inside wall of the pipe. The ultrasonic flowmeter is a clamp-on device that is designed with two transducers that serve as both a transmitter and receiver. In order to prove the concept, five stages of trials were planned and executed. In stage one, CT was rigged into a 150m vertical test well. The equipment included CT mast unit, CT pump, choke manifold, and acoustic monitoring device. Several debris piles from previous milling operations were introduced to the test well, and a CT cleanout was performed. The acoustic monitor system measured the amount of solid to surface, and the results were evaluated. Solids retrieved were then compared to the initial debris piles and correlated to the data received by the acoustic monitor. On the 2nd stage, the acoustic monitoring device was utilized in actual milling operation. The 3rd stage was a yard trial of ultrasonic flowmeter using a CT pump and data acquisition system to evaluate the working envelope of this device, followed by a field trial, in stage 4, utilizing the flowmeter in actual milling operations. The final stage of this trial was planned and executed in milling operations on a five wells pad, utilizing the combined applications of acoustic monitoring (solid measurement) and ultrasonic flowmeter (return rate) devices. All five stages contributed to proof of concept for the applications of solid measurement and return flow rate devices. These trials were successfully planned, executed, and evaluated. The acquired data throughout the five stages of these trials were utilized during and post job operations as lessons learned to optimize the process for future applications. The real-time measurement of solids and flow rate monitoring, independent of flowback operators, enables the CT operator to make informed decisions throughout milling and cleanout operations. The real-time streaming of solids to surface and return flow rate enables the operator and service company’s Engineering team to evaluate and optimize the execution of milling and sand cleanout operations.

Electric line deployed well intervention technologies are continuing to grow in use and relevance, this is due to the value provided by a highly efficient and effective means of intervention. It is light on equipment, personnel and logistics, is controlled and precise in its in-well execution, and is less obtrusive to the wellbore, the reservoir and the environment. These valuable characteristics are making electric line deployed solutions the preferred choice of customers for many interventions, whether that be for addressing new well completion, old well rejuvenation or repair, or eventual plug and abandon (P&A) operational scope. Preference is also increasing with those customers who are keen to push the boundaries of these technologies to leverage their beneficial impact across a broader range of intervention operations. Often, the tasks or workscope assigned to electric line deployed intervention technologies are reserved for what would be considered the lighter end of the spectrum, for example, low volume debris cleanout, small component milling and low force tool manipulation. However, as full system-based intervention technology platforms are developed, incorporating advanced interconnected technology components, the magnitude of what can be achieved has expanded electric line intervention solutions into the realms of work scope previously reserved for heavier methods, like coiled tubing or drill pipe based. That, coupled with the efficient and precise execution and inherently light footprint that electric line deployed intervention brings, is adding to the increased interest in expanding its use. Two recent electric line deployed wellbore cleanout operations carried out on the Norwegian Continental Shelf involving high volumes of debris demonstrate the advantages this advanced intervention technology platform has enabled, the scalability of its performance, and why it is challenging the traditional thinking and perception of what is possible on electric line. In the case operation 1, extensive volumes of produced sand had accumulated in a large mono-bore completion preventing the execution of a required P&A operation. In case operation 2, the well had significant Barium Sulphate (BaSO4) scale deposits over much of its length, which prevented well access for a required gas lift valve (GLV) change out. In both these cases, efficient and effective electric line deployed remediation was possible due to the increased performance, in-well task visibility and real-time task control provided by the advanced electric line intervention technology platform that was utilised. Attempting both these cases was strongly encouraged by the customer, leading a one team approach. For case operation 1, high speed tractor conveyance speeds of over 26 meters/minute were achieved on this multi-run operation. Instrumentation provided real-time indication of collection chambers being full, ensuring minimal time on depth during collection. Consistent high volume recovery rates of 100% were achieved on all but one of the collection runs, with a total of 1400 liters of sand debris being collected, clearing 280 meters of wellbore, at an average of 140 liters per 24 hours. For case operation 2, over 2000 meters of hard scale was milled, at a rate of penetration (ROP) of 44 meters/hour, on average, re-establishing access for required electric line intervention runs and the subsequent change out of the leaking GLV to restore the integrity of the well, enabling it to be put back on line and resume production. Record breaking achievements regarding the volume of debris removed and depth intervals cleaned via the intervention technology platform were made in both cases.

This paper outlines the capabilities and advantages of a 3 1/8-in. instrumented wireline tool designed for fishing or shifting in casedhole wells with up to 90,000 lbf with high precision and minimized tubular deformation. Some fishing necks have ratings higher than maximum capacity for linear actuators of similar size. To maximize the pull force applied to the fish, it was necessary to intervene with a linear actuator with a capacity at least as high as the fishing neck, but without increasing diameter to the point that it did not fit in the tubing or through restrictions above the fish. It is additionally necessary to accomplish this high pull without damage to the tubular where the linear actuator reacts the force applied to the fish. This imposes a requirement on the anchor module to avoid applying excessive radial forces to the inside of the tubular. A linear actuator was designed that has proven a pull capacity of up to 90,000 lbf to fish stuck tools without exceeding a 3 1/8-in. tool diameter. This module can achieve this feat with precision measurements on the force applied to the fish, the displacement of the fish relative to the tubular, the radial force applied to the tubular by the anchors, and the exact opening position of the anchors. It also carries onboard temperature and pressure measurements to detect changes in wellbore parameters when used for exercising stuck ball valves or sliding sleeves. Extensive simulations have been completed to aid in operational planning and ensure anchor pads do not damage the wall of the tubulars. Multiple anchor modules can be run in series to further distribute radial and axial loads if needed for thin-walled tubing. The use of high-precision instrumentation and high-strength mechanical design enabled a linear actuator to accurately pull twice as much as similar linear actuators with the same physical dimensions. This allows wireline to complete fishing operations in casedhole wells that were previously inaccessible either because of force requirements or diameter constraints, surpassing coiled tubing capacity.

Depth correlation before perforation is crucial in reservoir testing, to minimize the uncertainties about the reservoir being tested. Currently, three main methods are used to correlate to depth: simple pipe tally, tag of a known element in the well, or a wireline gamma ray (GR) log—which is the most accepted method, owing to its precision and track record. Wireline GR correlation, however, requires additional time (6 to 8 hours), translating into cost for the operator. We describe a new depth correlation tool, which is mounted directly in the drillstem test (DST) string and is enabled by a downhole wireless acoustic telemetry system, that provides correlation algorithm in real time without the need for extra wireline intervention. The introduction of a wireless-enabled GR measurement into the DST string radically changes the workflow for DST operations and results in significant reduction of rig time, as shown by one of our latest job campaigns in Qatar.

Coiled tubing (CT) operations in Texas are distributed in the Permian Basin and Eagle Ford plays supporting unconventional completion of horizontal wells using plug-and-perf technology. CT drillouts are a key step in performing the plug removal and achieving full production potential. From a wide variety of plugs available, the most common plugs are composite and dissolvable. This study presents an evaluation of both plugs for CT drillout. The analysis gathers post-drillout data from CT interventions in the Permian basin and the Eagle Ford: 63 wells completed exclusively with 2,664 composite plugs, 60 wells completed with a combination of both type of plugs for a total of 382 dissolvable plugs and 1,792 composite plugs, and 16 wells completed with 543 dissolvable plugs. Data were analyzed for correlations between well geometry; lateral length; plugs used; dissolvable plug location in the lateral (heel, toe, full lateral); and key performance indicators (KPIs) such as time in well, average milling, wash times, plugs spacing and total number of plugs. The evaluation was conducted by comparing wells completed with only composite plugs, only dissolvable plugs, or a combination of both types, and it included a review of dissolvable plug dissolution performance. Composite plugs show a consistent milling performance for laterals of 1 and 1.5 miles, with an average milling time of 4 to 5 min and a variance of 3 min and wash times of 26 min; for laterals longer than 1.5 miles, the performance declines. When evaluating laterals completed with dissolvable plugs average milling time is 7 to 9 min, and the variance increases with the lateral length, with wash times of 26 to 36 min. Wells completed with a combination of dissolvable plugs on the toe and composites in the rest of the lateral show an improved overall performance, with constant milling times of 4 to 5 min regardless of the lateral length and variance of 1 to 3 min; the overall time in the well when plugs are combined is reduced by 46% compared to laterals completed with dissolvable only. The analysis also determined that at least 45% of dissolvable plugs did not dissolve and required CT intervention. The aim of this is study is to give operators a tool to assess the costs and benefits of using different plug technologies with a strategic placement to execute interventions in the safest and most efficient manner. Additionally, dissolvable plugs are commonly associated with cost reduction related to eliminating the need for CT milling. However, the data shows that inconsistent dissolution of the dissolvable plugs adds an uncertainty factor, which can only be dissipated with intervention using CT.