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The coiled tubing (CT) injector is the equipment component used to grip the continuous-length tubing and provide the forces needed for deployment and retrieval of the tube into and out of the wellbore. Figure 1 illustrates a typical rig-up of a CT injector and well-control stack on a wellhead. There are several types of counter-rotating, chaindrive injectors working within the industry, and the manner in which the gripper blocks are loaded onto the tubing varies depending on design. These types of injectors manipulate the continuous tubing string using two opposed sprocketdrive traction chains, which are powered by counter-rotating hydraulic motors. Figure 1--CT injector and typical well-control stack rig-up (courtesy of SAS Industries Inc.).
The service reel serves as the coiled tubing(CT) storage apparatus during transport, and as the spooling device during CT well-intervention and drilling operations. The inboard end of the CT may be connected either to the hollow segment of the reel shaft (spoke and axle design), or to a high-pressure piping segment (concave flange plates), both of which are then connected to a high-pressure rotating swivel. This high-pressure fluid swivel is secured to a stationary piping manifold, which provides connection to the treatment-fluid pumping system. As a result, continuous pumping and circulation can be maintained throughout the job. A high-pressure shutoff valve should be installed between the CT and reel shaft swivel for emergency use in isolating the tubing from the surface pump lines.
Abstract Well BO-X is located in offshore East Malaysia and was completed as a single string producer on 22nd July 2014. Well BO-X has maximum deviation of 57.5 deg at depth 3,150ft MDTHF. Based on the MIT logs, several leaks have been detected on the string which caused the well unable to flow. Well was flowing for 2 years before identified with multiple leaks due to severe metal loss and high penetration along more than 1,400 ft tubing interval (400 ft above the TRSCSSV and 1000ft below the TRSCSSV). Multiple attempts tried to flow well but failed due to circulation of gas through leak points at tubing. Tubing was found to be leaking at multiple points above TRSCSSV (449 ft MDTHF) with severe pitting / penetration at a single point below between ESP discharge head and TRSCSSV from 2 MIT runs. The leaks were detected at depth (1) 64 ft MDTHF, (2) 126.8 ft MDTHF and (3) 221.2 ft MDTHF. There were also several potential leaks detected along the long string above the top packer Reservoir simulation studies and production rate both indicated that the production tubing leaks is deteriorate and few methods were considered to bring back the optimum production. Tubing pack off system technique was considered as it can deploy with slickline, retrievable and ideal use to isolate tubing leaks however there is potential that more leaks will develop along the production years. Workover as an option to replace the tubing could easily cost millions of dollar (USD) Before surrender the well to workover team, a coiled tubing patch system was designed in a cooperative project involving operator and service company to provide an improved tubing pack off system which can straddle the tubing leaks by using coiled tubing instead of spacer pipe. This coiled tubing patch system was significantly lower cost and keep the functionality of Tubing Retrievable Surface Control Subsurface Safety Valve (TRSCSSV) by installing two straddle packer system – upper straddle packer system to cover leak points above TRSCSSV while another straddle system to cover leak points below TRSCSSV (Fig 1).
Abstract Objectives/Scope A case study is presented detailing the methodology used to place a non-damaging temporary isolation barrier in a group of naturally fractured, prolific gas wells in a field in Kurdistan. The temporary isolation facilitated removal of the original completion string and installation of the redesign. Wells were returned to production with-out the need to stimulate proving success of the non-damaging methodology employed. Methods, Procedures, Process The operator had 4 wells with OH sections ranging from 33-181m which were completed in the 1980’s - 1990's with no production packer. In order to preserve well bore integrity the completion string needed to be pulled and replaced by a string with production packer and DH gauges. A procedure was developed to fill the highly fractured OH with a mixed particle size CaCO3 carried into the wellbore by a non-damaging surfactant based gel. Caliper logs were not available and the presence of natural fractures posed a challenge to calculating the actual OH volume. A system was developed to carry the CaCO3 into the wellbore in stages and slickline was employed to measure fill after each stage. Once the OH was filled with CaCO3 and well would support a fluid column coil tubing was used to place an acid soluble cement plug in the short interval between casing shoe and end of tubing (8-10m) Results, Observations, Conclusions The first well in the campaign required more than 10 times the theoretical volume of CaCO3 to fill the open hole. It was concluded the surfactant gel was likely carrying the CaCO3 into the fractures. The procedure was modified to tie in a line of breaker solution to the well head allowing sufficient viscosity of the fluid to carry the CaCO3 from surface but immediately lose viscosity and allow the CaCO3 to settle in the wellbore without being carried into the formation. Specific coil tubing procedures were employed to allow the setting of ultra-short acid soluble cement plugs (<10m). All wells were successfully isolated to allow the safe workover of the completion string and returned to production with no loss of gas flow, with-out the need to stimulate after the work over. Novel/Additive Information The campaign exhibited a new method of employing existing technologies to achieve the objective in a highly challenging and relatively new oilfield of Kurdistan. The campaign also demonstrated the benefit of the operator and service company closely collaborating on each step of a novel process. The workovers would not have been successful with-out the close collaboration of the two companies.
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.
Kalwar, Ghulam Murtaza (Saudi Aramco) | Hamid, Saad (Saudi Aramco) | Kishore, Sharat (Schlumberger) | Aljughayman, Abdulrahman A. (Saudi Aramco) | Abulhamayel, Nahr M. (Saudi Aramco) | Qahtani, Nasser F. (Saudi Aramco)
Abstract Latest developments in drilling and wellbore completion technologies lead to even more complex intervention conditions. Conventional techniques using slickline or coiled tubing are ill-suited for many of these conditions due to operational complexity, effectiveness, or efficiency. Powered mechanical intervention with e-line alleviates some of these limitations and opens lower risk intervention applications. This paper details two applications: a fishing operation that could not be performed with slickline or coiled tubing and a completion disk rupturing operation where the operator saved 1.5 days. Powered mechanical intervention is a combination of complementary technologies that enable "intelligently controlled intervention operations." Downhole tractors enable access into complex well trajectories. Surface-controlled, powered anchors coupled with a linear actuator can generate very high axial forces with precise and real-time downhole measurements of forces and displacement. Operating parameters can be monitored in real time to prevent damage to damaged completion components. Uncontrolled tool movement due to high differential pressures is prevented. Such precise control of downhole forces and movements enables complex intervention operations previously done with coiled tubing or a full workover. The first application example details a fishing operation. A retrievable plug along with its setting tool was stuck in the production tubing after prematurely setting. Multiple fishing attempts with heavy-duty slickline jars were unsuccessful. Coiled tubing was not deployed as its lack of force precision could have generated excessive downhole force and sheared the fish. An e-line-conveyed linear actuator tool was used to latch onto the fish with the help of an overshot and was released from the retrievable plugs by application of optimal, highly controlled, linear force to minimize damage. The second case involved rupturing a ceramic disk installed in completion. High differential pressure across the disk restricted the use of slickline which could have been damaged due to the high expected differential pressure. The alternative with coiled tubing milling requires a larger personnel and equipment footprint in addition to the associated HSE exposure and lack of efficiency. An innovative technique using the e-line linear actuator and a pointed chisel was devised and deployed. Real-time feedback from the tool sensors gave confirmation of the rupturing of various components of the ceramic disk, and the anchors eliminated any tool movement during pressure equalization. The operation was completed in 12 hours, resulting in time savings of almost 36 hours. An e-line intervention is a low risk, effective, and efficient solution while having an accurate depth and positioning, coupled with controlled downhole operations. With precise control of operating parameters, operations which were previously possible with coiled tubing or workover can be done on e-line more efficiently.
Abstract 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.