Li, Li (Shell) | Zhi, Guo Hong (Southwest Petroleum University, Schlumberger) | Millan, Hilarion (Shell) | Qiang, Zhang (PetroChina) | Tao, Zhang (Schlumberger) | Lei, Cui (Schlumberger) | Sheng, Li Yin (Schlumberger)
Changbei gas field is on the north edge of the Mauwusu desert in the Ordos basin in north-central China. The game-changing dual-lateral well concept is used in this tight gas reservoir. The typical well completion is kicked off at about 1700 m, and the hole is built to an inclination of 85° at the top of the reservoir with the 12¼-in. section. The first leg of the 8½-in. reservoir section is drilled for 2000 m. The second leg is drilled with an openhole sidetrack from leg 1. More openhole sidetracks are drilled from legs 1 and 2 if unstable intervals are penetrated. Upon reaching total depth (TD), a 7-in. slotted liner is run to protect any unstable claystone intervals.
As part of the well and reservoir surveillance activities and with the aim of improved understanding of the reservoir and well behavior, production logging is required to obtain the gas-contribution profile along the horizontal wellbore; the profile is used to confirm the size of the sand bar, facies distribution, wellbore condition, and production contribution from each leg. Previous attempts with wheel-driven tractors and conventional production logging tools (PLTs) were unsuccessful because most of the PLT runs encountered bad downhole conditions, such as water/mudcake, which led to failure of the tractors and PLT centralizers. The mudcake and debris could not be cleaned from wellbores, even though the wells had been produced at high rate.
To collect needed data, an advanced PLT consisting of an array of minispinners and optical and electrical holdup sensors was conveyed by an electrically powered tractor operating on the inchworm principle to successfully log a long-reach multilateral well. A workflow was followed to obtain wellbore accessibility and perform flow profile evaluation for the complex downhole conditions at Changbei. This was the first time a flow profile was obtained in Changbei block.
Coiled tubing (CT) monitoring tools are being utilized on a larger percentage of field jobs now as compared to the past. They are being used on both CT intervention and CT drilling operations. The objective of this paper is to demonstrate how a wall thickness measurement device can enhance and improve the calculations made by a CT fatigue algorithm.
Experimental work was done which shows how the wall thickness can vary depending on the pump rates, the fluid being pumped and the amount of tubing that is spooled on the reel. Reference four provides detailed information related to wall reduction in CT during pumping operations. Typically, fatigue models will utilize an estimated, nominal or minimal wall thickness to perform the fatigue calculations.
The amount of wall reduction in CT can vary greatly and as a CT string acquires fatigue, there is a chance that the estimated wall thickness may not reflect the actual wall thickness of the pipe. Recent modifications to fatigue tracking software allow the user to incorporate the real-time (or recorded) measured wall thickness into the fatigue calculations. This paper will discuss the experimental work, the modifications to the model, and case histories in which the wall thickness measurement device was used.
Calculating the CT fatigue using the measured wall thickness will increase the accuracy of the CT fatigue profile. This will allow CT service companies to operate at an increased efficiency. Operating companies will also benefit from this technology because there will be fewer fatigue failures at the well site due to the increased accuracy in the fatigue calculations.
Historically in our industry there have been many anecdotal claims of premature coiled tubing pipe failures during plug milling operations with recirculated fluid. Many of these failures shared related failure characteristics but no root cause was believed to have been identified by the service companies involved. In 2013, for one particular client, a series of failures on the coiled tubing string bias welds was observed, with a root cause due to the presence of sulfate-reducing bacteria (SRB) in the recirculated water. Two different mechanisms were identified as causing the premature failures on the bias welds: high-pressure corrosion fatigue that started at severe internal pitting caused by the presence of bacteria, and sulfide stress cracking caused by the SRB producing H2S.
A detailed analysis was also completed of time periods where fluid was spent stagnant in coiled tubing during rig-down/rig-up operations. Procedures were adjusted accordingly to prevent failure from further exposure to similar conditions by modifying recirculated fluid-handling volumes, improved biocide use, and rigorous multicomponent inhibition and purging during and between jobs.
Several specialist colleagues, familiar with SRB corrosion, were surprised at the speed SRB formed and created problems in coiled tubing in these environments. During the investigation process a rigorous fluid-testing protocol was developed. A prevention procedure was implemented during coiled tubing plug milling operations in this field. Afterward, no further coiled tubing failures were observed during similar operations in this area.
These failures have an industrywide impact in terms of personnel safety, operational disruption, and the cost and inconvenience of replacing coiled tubing strings. Information regarding coiled tubing failures related to bacteria exposure is only recently being published in our industry (
Clients utilizing Coiled Tubing (CT) for straddle frac operations in multi-stage horizontal wells often encounter cement stringers preventing the frac bottomhole assembly (BHA) from reaching plug back total depth (PBTD) and the packer from sealing to the casing wall. This paper presents the learnings from a >90 well campaign of preparing for fracking operations using an electric line (e-line) milling and clean-out tool. The wells were mostly cemented, 4.5? liners with frac sleeves. This technique reduced frac preparation costs in the cemented wells by approximately 30%.
The common practice in Southeast Saskatchewan (SE Sask) is to perform a “well prep” operation prior to the frac equipment's arrival to the well site. A CT unit equipped with a rotating scraper/mill—and associated fluids—is used for the clean-out, adding to the logistical coordination and well costs. Fluid has several costs associated with it: the cost of the fluid/water itself, heating for winter operations, trucking and disposal. However, “well prep” is considered “cheap insurance” by most operators working in SE Sask compared to the potential costs of a waiting frac crew.
An operator in SE Sask has had success with an alternative clean-out solution to replace the use of fluid for well preps by introducing an e-line method consisting of an electric milling & clean-out tool with a casing collar locator (CCL). The mill is conveyed by e-line tractor and is equipped with a scraper mill to confirm the PBTD and ensure that there is no cement debris or sheath present that could negatively affect the frac operation. Various bailers can be added to collect the cement debris in the same run and ensure it is removed from the wellbore.
In combination with the clean-out service, a CCL is deployed and logged to surface to pinpoint the exact sleeve location to be referenced during the frac operation. This new, efficient clean-out solution has proved slightly more time-consuming (~3-5 hours) but yielded significant cost savings of approximately 30% per well of prep costs. These savings come from using e-line equipment, eliminating fluid costs and offering inherently safer operations with a low carbon footprint.
Moreover, the paper will discuss the future applicability of this ‘additional application’ for pre-logging runs as a means to reduce total completion costs in cemented wells. This is achieved by using the e-line milling tool as a pre-run for casing inspections or cement evaluation logging.
Wiese, T. (ConocoPhillips Alaska Inc) | Yoakum, V. (ConocoPhillips Alaska Inc) | O'Dell, B. (ConocoPhillips Alaska Inc) | Loov, R. (Schlumberger) | Milazzo, B. (Schlumberger) | Nemec, J. (Schlumberger)
With approximately 1,200 wells and 47 developed drill sites in the Kuparuk River unit (KRU), North Slope, Alaska, a variety of well intervention services are required to keep wells in safe operating condition. Historically, conventional slickline and electric line services have performed a large portion of the non-rig diagnostics and repairs. With slickline operations generally limited to mechanical interventions and electric line required for depth-critical logging operations, both services are commonly required to complete a given well-work program. Because the intervention units are a shared resource, and the well-work schedule is priority based, there are often delays between slickline operations and the electric line diagnostics that follow.
Digital slickline services are being used in the KRU to improve overall well-work efficiency by completing intervention programs without the need for separate slickline and electric line services. Digital slickline services are being used to mechanically prepare wells for diagnostics, perform logging operations that would normally require electric line, and ready wells for repair without the need of additional service units. The enhancements linked to incorporating real-time surface readout data while performing mechanical interventions has reduced uncertainty and provided information for effective workover decisions. Using digital slickline technology has also mitigated risk exposure, as fewer crew hours are spent traveling and handling surface equipment. Examples of intervention work that have been completed with digital slickline services in the KRU include setting retrievable tubing patches, well integrity diagnostics and conventional slickline operations. The operations in the KRU have provided lessons learned and an understanding of the challenges associated with the technology.
CTD (Coil Tubing Drilling) has become a mature and successful technology in the continued development of the northern Alaska oilfields. Driven by advancing existing product limits and embracing new technologies, this paper details the development of a new completion technology that allows the operator to plan for and place pre-determined casing exit points within the wellbore to be accessed in the future as the well matures. This new technology addresses many of the typical limiting factors faced by operators when identifying future CTD candidates by reducing the typical preparation time, costs, and equipment limitations currently available to them.
The paper will show the viability and flexibility the operator gains by incorporating the use of pre-determined and spaced outer wedge assemblies affixed to the outside of the production tubing joints and run during the completion phase. The operator has the flexibility to run as many outer wedge assemblies as needed, based on their future field development strategy without imposing limitations on primary completion access or drainage capabilities. When required, an inner wedge assembly is then run and positioned within the outer wedge assembly, using a common wireline set tubing plug as a false bottom no-go. Orientation of the inner wedge is at the operators' discretion. The milling assembly will first mill through the production tubing before being deflected by the outer wedge assembly to then mill through the production casing. Details of the design, testing, and implementation of the system and components will be detailed within the paper.
This technology allows operators to plan for the life of the well at the completion phase. This reduces CTD preparation costs, provides simplified zonal isolation flexibility, and allows upper zones to be exited first if required. The technology reduces the risks and cost of dual string exits, while removing the need to leave an exposed large bore casing/liner at the exit point that could create difficulties during CTD drilling. Future advances and optimization of completion designs are expected to provide a cementless CTD liner completion while retaining zonal isolation capabilities within the wellbore.
Mechanical defects are incurred routinely in the coiled tubing (CT), and can have a first order influence on fatigue crack development. Failures of the CT can significantly impact operations and in a worst case can lead to the loss of a well. This paper developed the new non-contact CT assessment system with the new inspection method, which is suitable for the detection in-service and new coiled tubing. This paper proposes a new micro-magnetic detection technology for rapid detection in-service coiled tubing. The method is based on a high precision fluxgate sensor that measures the magnetic field changes in the geomagnetic field, without needing external magnetization and demagnetization to identify the location of the defect. We use iron base amorphous alloy to make the smallerfluxgate sensor. This method is effective in assessing the early damage and developed defects. Eddy current lift-off technique is used for the gap measurement and design ovality detection algorithm. The ovality is obtained through calculation of the software. The optical distance measure sensor measures down to the length of the coiled tubing. The test tool is designed and produced and can be installed and removed fast. 2D imaging is achieved and features the shape of defect. This system is available for various CT diameters. Data acquisition software real-time display flaws curve and the detection imaging. The tool can realize non-contact, measure wall thickness, diameter, ovality, and can fast nondestructively test in-service coiled tubing. The resolution of the testing instrument is 1 mm. It is easy-operating and time-saving, and has the maximum measuring velocity of up to several meters per second. Detection results are close to accurate location of prefabricated corrosion defects through inspection CT test sample. However, as a comparatively new test method, it still has a large room to be improved. Micro-magnetic measurement signals are weak, and its amplitude is small and unperturbed by the environment. Inspection of in-service coiled tubing still need to improve and develop.
The Buda formation in Texas presents extreme challenges to prevent formation damage during drilling operations. After using many fluid selection variations, several operators have determined that under-balanced drilling with native crude is the most optimum method. The initial startup project for coiled tubing drilling (CTD) operations in this formation has been completed, with more activity to come. However, as the preferred recirculation of the native crude drilling fluid presents two major challenges. First, the formation is up to 2% sour, and the native crude is relatively volatile with a low flash point and high vapor pressure.
Recirculation of sour crude will lead to double-sided exposure of the coiled tubing, which historically has resulted in extremely short fatigue life. The use of active fluid property testing, in addition to scavengers and inhibitors with defined mitigation plans, reduces the risk to an acceptable level. Significant laboratory testing of the fluid properties as the material degrades with time, temperature, and mixing have been completed. Additional mitigation actions are utilized in conjunction with the laboratory results to further reduce the volatility properties. Internal technical and operational reviews, along with additional sourced subject matter expertise, have challenged existing safety, operational, and technical limits. Operational procedures have been continuously monitored and adjusted to compensate for the adverse dynamic wellbore conditions encountered during the campaign.
The discussions within this paper detail the background challenges, laboratory testing, operational/HSE planning and mitigation practices to allow operations to commence. Additionally, the paper covers operational results as the wells are drilled. These results may provide a basis for future operations utilizing extreme fluid conditions in other applications within the industry due to the economic benefits from native crude.
Accidental plug setting and stuck tools is a cause of great frustration, operational delays and ultimately deferred production. A cost-efficient and swift resolution is always desired. This paper presents a new development in engineering in the form of a hydraulic stroking tool with the ability to apply 60,000 lbs of force. The tool has already been applied in the North Sea; lessons learned from these recent operations are disclosed in this paper.
In one operation, a plug was accidentally set across the Christmas-Tree (XMT) and blowout preventer (BOP), effectively eliminating the XMT as a well barrier element and constituting a serious HSE risk. Conventional solutions failed to release the plug due to an insufficient pull force and then a failing jar.
In another well, the setting tool had malfunctioned, resulting in a partially set plug and a stuck tool. Repeated attempts with heavy duty fishing equipment had damaged the fishing neck, further complicating the fishing operation as the seting tool had failed before it could break the stud connecting to the plug.
The high performance of the recently developed stroking tool turned out to be the solution to save both of these demanding operations. In the first well, it was estimated that the force required to shear the plug from the setting tool would be 43,300 lbs. The operation was completed in three runs with no misruns, which saved the operator from prolonged exposure to HSE risk, including well control situation.
In the second well, the force required to shear the stud and free the setting tool was 40,000 lbs. Two release devices were combined in the toolstring, one below the hydraulic stroker and one below the cable head in order to allow further contingencies to mitigate risk and increase safety. After four attempts, the shear stud parted, thus completing the setting sequence and freeing the stuck setting tool. The operator got the well back on track, saved five days of rig time and avoided the costs of a workover rig.
The case stories in this paper constitute the first jobs performed with the new tool. Two important features discussed are reduced HSE risks and increased operational efficiency.
Having a reliable backup plan is vital to ensure successful riserless light well intervention (RLWI) operations. This paper will present learnings from a subsea operation where the contingency solution was engaged to resolve a critical issue. The need for thorough back-up planning will be discussed along with the planning process, execution and lessons learned.
Crown plugs are conventionally retrieved using slickline jarring; however, high performance shifting tools on electric line are gaining foothold due to their ability to apply a focused, axial force downhole. Up to 33,000 lbs of force can be exerted through the use of a bi-directional, hydraulic ram. These electric line (e-line) stroking tools can be fitted with various shifting or pulling tools for lightweight mechanical services. For subsea interventions this is good news as space is particularly limited on vessels, which means that intervention solutions that simplify logistics by reducing equipment and crew is sought after.
The case to be presented is from a RLWI operation in the Gulf of Mexico where a crown plug had failed to release. Slickline (SL) was the first method to be put into action. On the first attempt 148 jars failed to retrieve the plug, then another 199 jars yielded the same result. It was believed that these repetitive attempts had broken the seal, resulting in saltwater inflow that had created hydrates. 25% Methanol Ethanol Glycol was pumped while jarring, but eventually the contingency plan was activated. This consisted of a hydraulic stroking tool, which successfully managed to remove the upper crown plug and thus allowed the operation to continue without further downtime.
The operator would have had six months of deferred production (being unable to open the sleeve to the upper zone) if the crown plug was not retrieved as they would have needed to wait for a riser. This underlines the importance of having an adequate contingency solution to overcome the challenges in riserless interventions. The benefits will be increased operational efficiency and reduced overhead costs.
This was the first operation where a crown plug was pulled during a RLWI operation with an e-line bi-directional stroking tool. The tool in this case was capable of 33,000 lbs of force; however, since the execution of this operation, further developments in engineering have led to a redesigned stroking tool with the ability to apply up to 60,000 lbs of force. What opportunities that opens up for RLWI operations will also be presented.