Well intervention in highly deviated sour oil wells operating with Electrical Submersible Pump (ESP) completions have always been challenging for well intervention operations due to the restrictions in the wellbore. Workover operations in such harsh environments involve several operational risks and high related costs. Electrical Coiled Tubing (E-CT) equipped with tubing encapsulated mono-conductor cable was used to gather accurate intervention data with real-time logging capabilities. The system used didn't require the temporary installation of a test ESP completion string after pulling the failed ESP pump, saving cost, overall intervention time, optimizing zonal isolation for the water producing intervals, and increasing well recovery in these oil wells. This case study presents a challenging workover for a mature field where E-CT was used to convey a combination of Pulsed Neutron Logging (PNLT) and Production Logging Tools (PLT) while pumping Nitrogen (N2) to lift the well. This enabled maximizing the reservoir production potential while monitoring the dynamic drawdown being applied to overcome the masking potential for the PNLT due to killing operations during workover. Real-time readings from the PNLT, PLT continuous spinners, gamma-ray, pressure, and temperature sensors accurately identified the well's water contributing intervals and flow profile. This accurate interpretation of the water saturation profile across the reservoir was then used for optimum reservoir management and selective zonal isolation. Dynamic wellbore modeling software was used to design the lifting and logging operations for optimal operational efficiency and to increase oil production and reduce water production. Deployment of E-CT in such a harsh environment was challenging in terms of operational execution to ensure safe conveyance of the real-time logging tools while performing the conventional lifting of the well. Intervention time was optimized through two runs to evaluate the formation performance and water saturation profile before isolating the water-producing intervals. Such utilization of E-CT allowed accurate formation evaluation, water saturation profiling, and nitrogen lifting of the well resulting in an optimal intervention. Results showed a 50% reduction in water production and an increasing well potential from the upper intervals. Total workover and intervention costs were reduced dramatically compared to other treatment options for water production problems with potential workover complications and deferred production.

Water production often has a big impact on limiting oil production from prolific wells, especially those supported by aquifers. When it comes to deep High Pressure, High Temperature (HPHT) wells, managing water production becomes even more complicated due to the challenges that limit downhole tool functionality, made even more complex when the source of water is from a channel behind the casing. A limited number of solutions are available for scenarios such as these. The subject well is located offshore in the Gulf of Suez and was drilled in 2010 to a depth of 14000 ft with a downhole temperature of 320°F and a reservoir pressure of 5700 psi. Due to complicated hole stability issues after drilling the 6 in hole, a 5 in liner could not be run to the well Total Depth (TD), so a 3 ½ in liner was run for over 1500 ft of the 6 in open hole section. This situation was far from ideal for a good cementing job, with the result being that the 3 ½ in liner was mostly uncemented, free pipe. Despite the selective perforating being carried out a long way from the Oil-Water Contact (OWC), water production kept increasing until it reached 95% in 2022. Saturation and production logs run in 2011 & 2017 showed that most water was coming from high-quality zones through cement channels behind the liner. Isolating the water source was considered; however, there would have been a high risk of damaging oil-bearing zones if conventional techniques were used. With emerging technologies and evolving chemistries gaining more reliability in the field, a team started to evaluate the various options to shut off the water production from behind the liner and rank them in terms of water isolation likelihood, operational risk & risk of damaging oil-bearing zones. The study focused on three possible solutions; shallow penetration polymer sealants, relative permeability modifiers (RPMs), and remedial cement operations. Coiled Tubing (CT) was chosen as the conveyance method to deliver the solution. The result of the study concluded that a specific design and procedure using shallow penetration modified, organically crosslinked polymer (m-OCP) system with a high content of properly sized Loss Circulation Material (LCM) would succeed in blocking water zones and bridge the oil-bearing zones for later recovery with selective re-perforation. The operation was carried out in September 2022 and successfully isolated 3000 BWPD while increasing well production by 2500 BOPD. In addition, the well started to flow naturally, saving the need for lift gas to use on other wells and decreasing the scaling risk in the well. A cost saving of approximately $1M was achieved in remediating this well. The alternative of efficiently drilling a new well to recover oil from the top low permeability zone would be estimated at $16M. Shallow penetration polymer sealants can be a cost-effective option to treat flow behind casing in challenging conditions. Expanding to an entire field could significantly increase production and maximize zonal recovery.

Sand production is a major challenge for many oil and gas industry operators, especially with unconsolidated reservoirs with weak bonding between the sand grains that enter the wellbore. This can eventually lead to damage to production lines and erosion effects to other surface equipment along with well productivity when drawdown exceeds the critical drawdown pressure. Although several techniques are used globally to combat sand production, most are uneconomical when considering the risk versus reward and the overall effectiveness in controlling sand production. An aqueous-based resin consolidation technique was evaluated for application in this case after the mechanical properties of the formation and sanding behavior in the field were estimated to be in the acceptable range for this technique to be applied successfully. An injection test followed by the aqueous-based consolidation treatment was bullheaded into the sand-producing zone resulting in minimal rig up and equipment required to operate. Post-treatment, a curing period allowed the resin to consolidate the coated sand grains. Compared to conventional resin, which requires large volumes to coat the near-wellbore region, this treatment used only a small volume of active resin. This effectively coated and cured in the near-wellbore region, providing excellent consolidation strength allowing the well to produce without any sand particles under the same drawdown applied to offset wells in the field. A case study is presented in this paper illustrating an effective, cost-efficient, and proven sand control solution for the high potential reservoirs of Libya. This solution can help develop fields that previously suffered from impaired well productivity and required expensive formation sand handling and disposal. Such a solution restored oil production without any considerable effects on the relative permeability of the formation to hydrocarbon or water while maintaining sand consolidation without any further sand production problems.

This paper represents a challenging rig-less intervention in highly deviated wells with heavy oil that has always been a challenge to conventional electric line (e-line) that is not a valid intervention technique due to its inherent limitations in these harsh environments. Electric Coiled Tubing (E-CT) was utilized not only to achieve safer deployment of the guns, but also to allow real-time operations on three wells which were inaccessible due to heavy oil content and restricted e-line accessibility. A case study is presented for a campaign performed using E-CT to convey the perforating string while pumping nitrogen (N2) to lift the well and achieve flowing under-balance to maximize perforation clean-up and minimize skin. Real-time readings from gamma ray, pressure and temperature sensors were used to accurately position the guns, generate the desired dynamic underbalance, and finally validate successful detonation based on pressure and temperature responses. This was achieved while N2 lifting and firing the guns to optimize the required under-balance value providing immediate feedback related to the production gain to determine the zonal contributions and maximize the economical production gains. Dynamic wellbore behavior software modeling was also used to predict the dynamic under-balance effect for maximizing perforation efficiency. Deployment of E-CT was very challenging in terms of operational execution but was extremely beneficial for the safety of the pipe during such operations. A total of 13 runs comprising of milling, tubing cleaning and drifting were performed to remove the accumulated scales inside the production tubing and to ensure full accessibility to target intervals. Coiled Tubing (CT) dynamic modeling software was utilized to simulate the N2 rate needed to achieve the target underbalance while maintaining safe perforating parameters for the CT while firing the guns. As a result of software simulations, one of the three wells was then recommended for an acid wash treatment which achieved very effective results. 15 perforation runs were performed on the three wells re-perforating a total of 188 ft of interval, resulting in a production increase of more than 300%. This was a significant improvement compared to the previous campaign carried out in 2017 where perforating in static conditions showed no increase in production without work-over rig intervention. E-CT intervention also eliminated the need for waiting on rig schedule and avoiding deferred production.