An innovative methodology using a new bottomhole flow measurement tool and distributed temperature surveying was used to treat two openhole carbonate water injectors using coiled tubing (CT) equipped with fiber optics. The system capabilities were leveraged to control, in real time, the dual injection process and ensure that the treatment covered the entire horizontal section. The new level of efficiency of this approach was proven in the outstanding results of this stimulation campaign.The method takes advantage of the fiber optics present in a CT string to acquire, in real time, both downhole flow measurements and distributed temperature surveys to identify areas of higher and lower injectivity along the wellbore. It also enables clear and rapid evaluation of the depth to the level that bullheaded fluid would normally reach downhole. The real-time flow measurement is further used to optimize the stages of the treatment that aim at placing fluid across the interval initially poorly covered, as it gives direct feedback of the efficiency of the pumping through the annulus and CT.Matrix stimulation in water injector wells is often handled in a straightforward way by simply bullheading the treatment from surface. Used within the context of horizontal or highly deviated openhole wells, this frequently leads to an overstimulation at the casing shoe or along the first part of the zone of interest, and a significant section of wellbore is poorly covered or even remains untreated. The new approach not only enables visualizing where the treatment fluid goes, it also gives a new level of control of downhole injection, in real time. This new capability was taken advantage of within the context of long horizontal openhole water injectors, whose previous stimulation treatments left untouched a significant portion of the reservoir, even when complementing bullheading by the placement of treatment fluid with CT. The methodology enabled clear identification of which pumping method was beneficial to which interval. It also proved very efficient, leading to an increase in the injectivity index of the wells of nearly threefold, beyond the expectations based on previous stimulation interventions.The new downhole flow measurement tool and its use within this innovative workflow address many limitations usually encountered during the stimulation of horizontal or highly deviated openhole water injectors. In particular, the approach enables taking full advantage of the dual injection process, which often proves difficult to control and optimize in real time. The end result is an unprecedented level of efficiency of the process.

Cantarell field produces a significant portion of the total oil production of PEMEX. Over the past few years, Cantarell oil production has been declining, mainly because of the maturity of the field. Sustaining oil production at current levels is a constant challenge for PEMEX, which is also attempting to increase exploration. One of the main challenges involves an increase in water production, which has led to wells being temporarily shut in until a workover rig becomes available. This waiting time could be years. Meanwhile, PEMEX is investigating alternative solutions to optimize rig utilization and offshore rigless workover options. Recently, coiled-tubing-conveyed inflatable packers have become a key enabler when performing workover operations while the production tubing remains in place, which enhances timely and cost-effective intervention solutions. Through-tubing inflatable packers have successfully isolated zones during water-control treatments, cementing operations through coiled tubing (CT), and permanent zonal abandonment, thus enabling the operator to perforate the upper oil-bearing zones. The use of through-tubing inflatable packers for zonal isolation is now featured in the rigless workover plan for several wells, which is expected to deliver a significant increase in oil production. This paper examines these recent applications of through-tubing inflatable packers in the region and presents the relevant well conditions and the criteria used for selection. It provides case histories and best practices from several through-tubing applications. Recommendations for job design, auxiliary equipment, and personnel competency are thoroughly discussed. Introduction Cantarell basin is located 75 km northeast of Ciudad del Carmen, Campeche. The field was discovered in 1975 with the perforation of well Chac-1. Quickly, Cantarell became the largest contributor of Mexican oil production. Cantarell has six producing fields, Akal, Nohoch, Chac, Kutz, Sihil Ligero, and Sihil BTPKS. The producing formation is mostly naturally fracture dolomite with average permeability up to 4000 md, and a 600 m. net pay. The produced fluids are typically 22-degree API oil, with a 65 m3/m3 gas/oil ratio (GOR) and an average reservoir pressure of 1350 psi. The field production is assisted with gas lift because of the low pressure of the reservoir. By 1995, a total of 152 wells were producing, and the formation pressure started to drop dramatically. In 2000, PEMEX launched a very ambitious project, including the drilling of 213 wells, the development of a nitrogen injection complex to maintain the reservoir pressure, and modernization and building of new infrastructure. As a result of this project, in early 2003, the field reached its maximum historical daily production, which has been declining since then. Actually, the Cantarell basin already has 418 wells drilled, 205 of them are producing, and more than 100 wells are shut in, scheduled for workover. The operator has 28 satellite platforms with only 20 drilling/workover rigs to intervene them. Then, effective asset utilization as well as rigless intervention is mandatory to maintain the actual production levels. Some of the problems that the field has been experiencing are water invasion on the lower oil-bearing zones and high GOR and N2 content on the upper oil-bearing zones. In most cases, the workover objectives involve plugging the invaded zones to produce another zone. The traditional procedures for change of intervals with workover rig include:Temporary zonal isolation (to act as second barrier for Christmas tree removal).BOP and rotary table installation.Production tubing pull out of hole (POOH).Permanent zonal isolation.Production tubing runs in hole (RIH).New zone perforation.Kickoff.Deliver well to production facilities. Zonal isolation can become very difficult for several reasons: poor cement bond behind the casings, returns cannot be attained on surface because of the low reservoir pressure, and the huge permeability on the open zones prevents effective control on fluid placement. The same problems are experienced when zonal selective treatments are pumped.1

Production in offshore Mexico mature fields is mostly driven by gas injected from surface. With time, this injected gas flows directly through the natural fractures of the low-pressure carbonate reservoirs, leaving oil trapped in the low-permeability matrix. Over the past few years, the gas-oil contact (GOC) has rapidly moved across those fields—up to 6.5 ft per month in some wells—, making conventional gas shutoff techniques either unsuccessful or uneconomic. A new rigless intervention method using coiled tubing (CT) equipped with real-time telemetry has been used to revive oil production in gas-invaded wells. The objective was to achieve better results than the mixed success that had been obtained with gas shutoffs using chemicals and to reduce the cost and time typically involved with traditional workover operations. The approach consists of the modification of the downhole completion through CT. After perforating a new interval in the lower oil-bearing zone, a CT string is conveyed down the well and precisely hung by another CT at the end of the existing production tubing. Equipped with slotted bars, the string allows directly tapping into the newly opened zone while bypassing the former intervals that are mostly producing gas. From a CT standpoint, such interventions in an offshore environment present significant challenges, ranging from logistical to operational. During the first implementation of this new technique, the available section for anchoring the CT hanger was only 11.5 ft of 3 1/2-in. tubular inside a 5 1/2-in. completion. In addition, the projected tail of the CT hang-off was very close to the well total depth (only 10 ft from the bottom). The use of CT with real-time telemetry was thus critical to an accurate depth control that would allow not only determining the actual length of the CT string to be cut, but also for precisely hanging that string. In addition, the joint use of real-time telemetry and a downhole tension and compression module was key to ensuring proper actuation of the anchoring mechanism downhole while protecting the integrity of the new and former completion components. As a result of that intervention, the gas/oil ratio was reduced by 96%, while oil production increased more than twofold. In addition, the use of the CT measurement system and its flexibility saved a major workover intervention and the associated deferred production to the operator. This rigless methodology, leveraged by CT real-time telemetry, brings a new, viable, and economical alternative to gas-control treatments. Use of the technique can significantly extend the life of producers facing major gas-control issues in environments where the complexity of the reservoir and its dynamics tend to make shutoff treatments complicated and their outcome uncertain.

Scale buildup due to water production can choke oil production and require repetitive scale treatments across entire fields. In subsea wells, the common solution employs a deepwater rig to conduct either workover operations or large-volume scale inhibitor squeezes. Less frequently, coiled tubing (CT) is used from a moonpool vessel. However, current oil prices required a custom solution for subsea well treatments that was more cost effective than either a rig or a moonpool vessel. Similar previous operations successfully used 1 ¾-in. and 2-in. (44.4 mm. and 50 mm.) CT at the same time from a moonpool vessel. A remotely operated vehicle (ROV) in the open water connected the CT to the subsea safety module (SSM) through a dynamic conduit and connected the SSM to the wellhead. An engineered solution to change to 2 7/8-in. CT and use high-rate stimulation pumps was planned to deliver subsea treatments at up to 15 bbl/min. The equipment layout was designed for a multipurpose supply vessel with chemical storage tanks; to increase the available selection of vessels, the CT was designed to run overboard rather than through a moonpool. This project was initiated after accelerated scale buildup occurred because of a pressure decrease close to the bubble point, which happened when the drawdown was increased for aggressive production targets. To effectively inhibit scale in this environment, treatments required thousands of barrels of inhibitor. For wells with more-severe scale conditions, acid treatments were planned. These treatments were delivered with one complete CT package, stimulation pumping fleet, and subsea equipment, which were all installed on the spare deck space of the available vessel. A custom overboard CT deployment tower was designed. The new tower improved the dynamic bend stiffener (DBS) placement, which allowed the clump weights to be deployed with the bottomhole assembly (BHA) and simplified the rig-up. The chosen vessel worked well for the operation; however, the equipment layout and the local weather conditions combined with the response amplitude operator (RAO) of the vessel shortened the projected fatigue life of the CT. CT integrity monitoring with magnetic flux leakage (MFL) measurement was introduced here, and the vessel’s motion reference unit (MRU) provided an input to a fatigue calculator, based on the global riser analysis (GRA). The measurements and the analysis were utilized successfully to prevent CT pipe failures in the open water and deliver the required well treatments. To allow further improvements in deepwater operations, the new engineering work-flow was carefully documented.

(300 words) This paper describes the lessons learned during the completion phase of an unconventional well in Argentina. Where a coiled tubing was used to perform a plug drill out campaign. The article describes the procedure of how the CT service provider followed to release a stuck pipe, the well barrier regains and its recovery. The potential solutions were analyzed by the engineering teams from both CT service provider at local and headquarter levels and the local vendors. The fact of cutting the pipe after getting stuck and unsuccessful retrieval attempts result on losing the well control barriers inside the CT pipe. There was a need to regain the well control before proceeding with the retrieval process. The use of a mechanical agents to plug the pipe was assessed, it was considered internal mechanical plugs that due to logistics will result in excessive times. Therefore, the team looked into the chemical solutions, and cement plug was also visualized but discarded due to tendency of laying down in the horizontal section of the wellbore; Finally, a high viscous resin that is fast setting time was evaluated as the optimal solution to set a plug inside the CT, which was the key to success on the safe retrieval operation. The Argentinian well was completed with 57 stages isolated by 56 dissolvable plugs over 3000 m of the horizontal section. After removing all the plugs in the horizontal section down to total depth. CT pipe was being retrieved to surface performing the final wiper trip, when it got stuck. After several unsuccessful release attempts. The decision was to cut the CT pipe at surface to allow the wireline to perform the downhole cutting. Wireline (WL) rigged up on top of the injector head and performed a tubing puncher run, 3 m below the cutting depth. Then, WL perform a second run at the free point, at a depth of 3900 m, deploying a chemical cutter to release the CT pipe. Once the CT pipe was confirmed free, the resin service company, proceed to install their high-pressure lines in the top of the injector head and proceed to pump 6.7 bbls of resin at a pump rate of 1.5 bpm, displacing it with 5 bbls of gel and 30 bbls of water leaving the bottom of the plug 500 m above of the new CT end. After the thickening time, a pressure test of the plug was done up to 8000 psi for 30 minutes followed by an inflow test of 6 hours, after the successful completion of both, the retrieval of the CT pipe was followed. This project describes the design and execution process of pumping a resin plug, without previous experience within our organization at global basis, that is suitable to regain well control on CT pipes that lost the downhole safety valves after being cut due to a stuck condition.