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Frantz, J. H. (Deep Well Services, Matador Resources Company, Completion Team) | Tourigny, M. L. (Deep Well Services, Matador Resources Company, Completion Team) | Griffith, J. M. (Deep Well Services, Matador Resources Company, Completion Team)
Abstract In conjunction with the industry and basin-wide paradigm shift to drilling and completing extended laterals, Matador Resources Company (the operator) made significant plans in 2018 that would focus activity toward wells with laterals greater than one-mile. One operational hurdle to overcome in this shift change was the effective execution of removing frac plugs and sand at increased depths during a post-stimulation frac plug millout. Utilization of coiled-tubing units (CTUs) had been proven to be a successful millout method in one-mile laterals, but not without risk. Rig-assisted snubbing units coupled with workover rigs (WORs) provided for less risk with higher pulling strength capabilities and the ability to rotate tubing, but would often require operational time of up to twice that of typical coiled-tubing unit millouts. The stand-alone, rigless Hydraulic Completion Unit (HCU) was ultimately tested as a solution and proved to alleviate risks in extended lateral millouts while providing operational time and cost comparable to coiled-tubing units. The operator has since performed post-stimulation frac plug millouts on ~45 horizontal wells in the Delaware Basin using HCUs. The majority of these wells carried lateral lengths of over 1.5 miles. Results and benefits observed by the operator include but are not limited to the list below: 1.) Ability to safely and consistently reach total depth (TD) on extended laterals through increased snubbing/pickup force and the HCU's pipe rotating ability 2.) Ability to pump at higher circulation rates in high-pressured wells (>3,500 psi wellhead pressure) to assist in effective wellbore cleaning 3.) Smaller footprint which allows for the utilization of two units simultaneously on multi-well pads 4.) Time and cost comparable to a standard coiled-tubing millout, particularly on multi-well pads.
Abstract 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.
Abstract 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.
Abstract 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 , and the resulting tubing material response leading to failure.
Abstract Over the past years the usage of coiled tubing as a prefer method to deploy long and heavy guns in highly deviated wells has been widely spread in the oil industry to provide a single run without killing the well, perforate in underbalance conditions, reduce risks and improve job efficiency. The three wells are located in the Caspian Sea. In two wells, the objective was to isolate lower intervals and perforate a new zone through tubing and casing between two packers. On the other well, the objective was to perforate a new interval through casing after running a new completion and isolate lower production zones. Due to the challenges involving gross length of the new intervals, guns size, well deviation and live deployment needs several techniques were evaluated. The best approach was to use an Advance Live-Well Deployment (ALWD) system to deploy and retrieve the guns with a tube wire-enabled Coiled Tubing Telemetry (CTT) system focus on both safety and cost saving compare with conventional wireline perforating. Extensive job planning involved coiled tubing (CT) simulations to reach target depths, shock loading modeling to ensure forces are within CT string limitations, system integration test to verify deployment/reverse technique procedure and system communication to electrically activate guns. CTT integrated sensor assembly was used during deployment/reverse operation with a tension, compression and torque (TCT) sub-assembly to monitor accurate upward/downward forces. In addition, CTT logging adapter assembly was used for depth correlation and electrical guns activation. The ALWD system; composed by connectors and deployment blow out preventor (BOP), prove to be an efficient way to run, perforate and retrieve gross intervals of 212 m, 246 m and 104 m with guns successfully. During all these jobs several lessons learnt were created in order to improve the deployment/reverse procedure for future jobs including not only operational steps but also deployment/reverse bottom-hole assembly (BHA) configurations. Based on the success of these case histories, the ALWD combined with CTT system has been proven to be the preferred method when dealing with long perforation intervals in life well conditions, thru-tubing environment.
Abstract 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.
Abstract Coiled tubing (CT) integrity is critical for well intervention operations in the field. To monitor and manage tubing integrity, the industry has developed a number of computer models over the past decades. Among them, low-cycle fatigue (LCF) modeling plays a paramount role in safeguarding tubing integrity. LCF modeling of CT strings dates back to the 1980s. Recently, novel algorithms have contributed to developments in physics-based modeling of tubing fatigue and plasticity. As CT trips into and out of the well, it goes through bending-straightening cycles under high differential pressure. Such tough conditions lead to low- or ultralow-cycle fatigue, limiting CT useful life. The model proposed in this study is derived from a previous one and based on rigorously derived material parameters to compute the evolution of state variables from a wide range of loading conditions. Through newly formulated plasticity and strain parameters, a physics-based damage model predicts CT fatigue life, along with diametral growth and wall thinning. The revised modeling approach gives results for CT damage accumulation, diametral growth, and wall thinning under realistic field conditions, with experimental validation. For 20 different coiled tubing alloys, it was observed that the model improved in accuracy overall by about 18.8% and consistency by 14.0%, for constant pressure data sets of more than 4,500 data points. The modeling results provide insights into the nonlinear nature of fatigue damage accumulation. This study allowed developing recommendations to guide future analytical modeling and experimental investigations, to summarize theoretical findings in physics-based LCF modeling, and to provide practical guidelines for CT string management in the field. The study provides a fundamental understanding of CT LCF and introduces novel algorithms in plasticity and damage.
Abstract A fracture treatment in offshore Tunisia screened out leaving over 76,000-lbm proppant in the wellbore. The well was significantly under-hydrostatic. The platform was small and had limited deck space and low capacity cranes. The completion incorporated chrome tubulars with a history of causing abrasion failure to coiled tubing strings. The challenge was to efficiently and safely clean out the proppant with coiled tubing (CT). A prior cleanout campaign had been conducted with concentric CT and jet pumps. An initial design focused on repeating this method. The engineering analysis had to account for fluid and nitrogen pumping being conducted from a supply vessel, limited nitrogen volume, low the solids return rate due to surface handling limitations, and no fluid discharge permitted to sea. A combined engineering, logistical study, laboratory testing and risk assessment was undertaken over the course of three months. Engineering utilized advanced cleanout modelling software to review concentric CT cleaning, forward cleaning (with and without optimizing cleaning Bottom Hole Assembly (BHA) and with various sizes of CT), and reverse circulating. Logistics analyzed the overall operation time, fluid and nitrogen requirements and the number of boat trips to replenish/change well returns and nitrogen. Three additional challenges were present. First, proppant could have packed off creating difficulties for some of the processes under review. Laboratory testing was conducted and confirmed this would not be a concern. Second, the well was sour and considerations for protecting the CT string and handling hydrogen sulfide (H2S) in the return stream were required. Third, CT string optimization was required to reduce potential abrasion failures. Avoiding CT failure was paramount as the string would be boat spooled onto the platform and any failure would severely impact operating time and project finances. The chosen method was primarily fluid only reverse circulating when cleaning above the formation, changing to forward circulated two phase operation when close to the formation. The downhole pressure gauge in the completion provided early warning of lost returns or of gas kicks. The operation was successfully, efficiently and safely completed in August 2019. The well was handed back to production 8 days ahead of schedule. The paper will cover the complete concept and detail design, execution and post-job analysis.
Abstract 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.
Abstract Annular Frac operations performed with Coiled Tubing (CT) offer many advantages for unconventional completions, particularly wells with long laterals and many pay zones (frequently in excess of 100 stages). The primary disadvantage to annular frac is erosion of the coiled tubing due to impinged, high pressure fluids containing abrasive frac sand. This paper will describe a methodology to detect erosion of the CT to provide consistent, reliable operations. When designing equipment and writing operational procedures to detect erosion in annular frac through coiled tubing, the following considerations may be considered: CT string design and pumped fluid flow rate when fracturing. From a CT service company perspective, the fluid dynamics of the pumped fluid may contain uncontrolled variables such as fluid density, viscosity, and slurry from job-to-job. As a result of the limitations noted above, the onset of erosion may be difficult to predict. However non-destructive electromagnetic inspection can be utilized to highlight possible locations of erosion within CT strings to develop "field-tested" guidelines for pumping against tubing size. Electromagnetic inspection using Magnetic Flux Leakage (MFL) and/or Hall Effect Sensors can highlight localized variations in wall thickness. However, this information alone does not give a clear indication if the tubing has been damaged by erosion without a baseline inspection to compare to, since there can be variations in wall due to the CT manufacturing process and the prevalence of tapered CT string designs. If the CT string is inspected either when new or very early on in its life, a comparison of wall variation by electromagnetic methods can "rule out" wall thickness variations that were present at the time of manufacturing. Evaluation of CT strings with electromagnetic inspections performed when new and after retirement will be presented in this paper. The inspection results will then be supplemented by pumping parameters from annular frac jobs performed with these strings. This paper describes a methodology of verifying that CT strings have not been subject to erosion due to annular frac operations. An exploration of pumping rates used on these strings in operations also provides some "field-tested" practical guidelines for avoiding erosion when performing annular frac jobs.