The XK field is a mature offshore asset with post peak production characterized by rapid oil decline rate and steep water cut. Many wells have ceased flow prematurely over time and non-rig interventions to reactivate and restore the wells to production had typically been ineffective owing to consistent low tubing head pressures and well construction/completions. Furthermore, the plan to initiate gaslift operations in the field was challenged by the lack of gaslift separator, compressor unit and gas line coupled with the fact that many of the wells were completed without gaslift mandrels. The deployment of innovative inter well gaslift, utilizing Gas Liquid Cylindrical Cyclone (GLCC) separator saved the situation and enabled achievement of the gaslift objective. The result was the successful restoration of three (3) long shut-in wells and associated increased oil production in the field. This paper discusses the opportunities and challenges from inter well gaslift initiation and operations in XK field and the enormous potential as a low cost and efficient system for rejuvenating Brown Fields.

In challenging horizontal wellbores with subhydrostatic well conditions and the inherent uncertainties associated with mechanical bridge plug installation, the balanced cement plug concept becomes the appropriate method for cement packer installation. The balanced cement plug method requires creating a balanced U-tube with the hydrostatic pressure consisting of a column of brine, spacers, and cement slurry in the annulus of a tubing/drillstring equating the hydrostatic head in the drillstring/tubing and annulus. Fluid volumes are calculated, accounting for fluids both inside and outside the pipe at the given gradient/head, resulting in a hydrostatically "balanced system." Recently, this technology has been successfully deployed for cement packer design and installation using coiled tubing (CT) to place 813 ft of cement packer in the 3 1/2-in. tubing × 9 5/8-in.casing annulus from bottom of tubing punch at 5,913 to 5,100 ft MD (685 ft above shallowest perforations). The location of the production packer at a depth of 629 ft with 9.6-lbm/gal calcium chloride brine (cement accelerator) existing below the tubing punch interval in the tubing-casing annulus presents challenges with respect to the cement slumping through the brine. Detailed engineering design and execution is necessary to overcoming such inherent challenges. The zonal isolation of the existing subhydrostatic mature oil zone within the horizontal wellbore (793 ft blank liner and 1,698 ft predrilled liner) was achieved through placement of 575 ft of cement plug in the 3 1/2-in. tubing from 6,511 to 5936 ft MD. A rigless through-tubing balanced cement plug concept for cement packer installation and reperforations was deployed to access behind pipe oil reserves in a high-angle (69 to 72º) deviated well, Offshore Niger Delta. Design considerations were reviewed and precautions for placement through CT were discussed. The operation was successfully executed and the temperature log confirmed the TOC as proposed during the design phase. The HUD in the tubing was also tagged as expected with no cement U-tubing from the annulus. Post-job shut-in tubing and casing pressures, quantity of cement pumped, and flow tests have proven the success of the design and procedure implemented in challenging wellbores. The stable production post-hookup to the production line presents 212% incremental production without sand exclusion against the proposed well intervention objectives. This presents the advancement in cement packer installation in complex well trajectory with high potential of U-tubing attributed to failed retainer packer for accessing bypassed oil reserves. The balanced cement plug engineering design presents an interplay between 8.5-lbm/gal inhibited sea water, 8.33-lbm/gal spacer (drill water+surfactant), 8.5- and 9.7-lbm/gal brine, 15.8-lbm/gal neat cement slurry above the 9.6-lbm/gal existing completion calcium chloride brine, and pressures in the casing/tubing annulus and tubing to balance the fluid without a retainer packer.

The unique introduction of production screens with mechanically shiftable flow isolation sleeves and inflow control devices for better injection flow distribution (ICD) fit with innovative dissolvable metal plugging rods that allow wash pipe free horizontal completion installation on a deep offshore project in Nigeria. This unique application provides the function of a mechanical selective completion with the incorporation of an ICD solution tailored to the reservoir with wash pipe-free execution. This would allow for selective injection from one zone to a comingled injection activated using mechanical intervention means while maintaining full compatibility with the already designed upper completion and the existing wellhead and topside equipment, as is. The completion was successfully installed following the standard field operations practices used on previous completions within the same field. The Egina development plan, operating with a standardized and simple design, does not provide for an intelligent completion that allows remotely activated zonal selectivity. Two separate reservoir zones, with two panels each, were targeted for water injection to achieve the sweep of by-passed oil in the shallower panels connected to two producer wells and pressure mainteneance in the deeper panels connected to one producer well. Commingled injection from start would result in early water breakthrough on one of the two producer wells connected to the shallower reservoir panels by virtue of both well drains being almost at same level depthwise, TVD/MSL. A solution was selected that would combine the two target reservoir zones on a single well. This would allow for selective injection using screens with mechanically shiftable integral sliding sleeves, maintaining temporary access or isolation on the shallower interval. This solution would allow for drilling one single water injection well instead of two. Incorporating ICDs in the deeper reservoir panels with " a dissolvable plug solution " allowed for a better injection flow distribution as well as the completion deployment, wash pipe free. Fluid compatibility testing was performed with dissolvable metals to establish dissolution rates under existing reservoir conditions with mud, brine, and filter cake breaker at field standard formulations. This provides an additional option for running wash pipe free when running lower completions in deepwater wells offshore West Africa. Drilling one well instead of two and deploying completions wash pipe free, allowed for CAPEX savings in the region of $60 Million. No modification to the existing completion processes was necessary with respect to the procedure for deploying completions, washing down or subsequently placing a filtercake breaker treatment. This paper describes the rationale behind the well design philosophy and the operational procedures that introduced a global first deployment of injection screens with mechanically shiftable integral sliding sleeves and ICDs with dissolvable plugs in deep water openhole horizontal completion. The successful installation, completion equipment functionality, and well injectivity test results are discussed.

Wax precipitation along oil well tubing causes deferment in production while being produced from the formation through production facilities. Existing formulations for inhibiting wax formation include, chemical injection at different dosages and depths, mechanical inhibiting forms and thermal methods used in overcoming wax formation temperature. A well in one of the Niger Delta offshore field suffered down hole wax deposition after each field shut down. A triplex pump which serves six fields was used to provide a remedial solution after an average well downtime of seven days. In order to control this challenge, crude oil pour point was determined from historical production and temperature profiles and a hot reservoir fluid circulation strategy was developed with the objective of optimizing production through reduced well downtime and minimized expenditures. The technique used shall be discussed in this work. This formulated strategy saved over a five million US dollar per annum.

The importance of Wells, Reservoir, and Facility Management in the life of producing Oil and Gas assets cannot be overemphasized. Several authors in the past have highlighted the significant contributions WRFM practice and process have to the ultimate recovery of matured assets. WRFM serves as a stop-gap to redevelopment in areas of cash crunch, whereby active WRFM practice arrests severe natural decline in production. Onshore assets comprising of fields Alpha and Beta are operated by Shell Petroleum Development Company (SPDC). These assets have been operated for over 30 years, rising water cut & high gas-oil ratio production and facility downtime risks have impacted oil recovery. This work showcases the application of WRFM at the re-startup of production in these fields post shut-in for almost 5 years. Effective and deliberate application WRFM processes and practices woven together in the WRFM Plan not only ensure an efficient restart of the facility but the ability to ramp production while maintaining the intricate balance of good reservoir management. The paper will highlight the best WRFM practices which enabled the resumption of production at a lower water rate compared to when the field was shut and maintain this higher net oil for a prolonged time. Also highlighted are opportunity identification and implementation in-closed wells and effective collaboration across disciplines to ensure a safe and efficient restart of production facilities.

Managed by a joint operating team tagged the Asset Management Team (AMT), the OML 26 Asset has undergone a total transformation in all ramifications of the oil and gas operations. Within the space of three years, the Asset has recorded a 122% cumulative annual growth (CAGR) for reserve base increase, a 43% CAGR in production rate increase without drilling new wells, and a 38% CAGR in total production offtake. The direct unit operating cost also improved significantly averaging 31% year on year improvement. From Q4 of 2018, the Asset witnessed breakthrough performance attaining a peak production of ca 18,000 bopd in 2019 from existing drainage points. The rate is the highest rate ever recorded in the long history of the Asset. This is an excellent achievement for a mid-sized E&P company. This paper aims to share the techniques deployed to attain such a sterling production boost in a 45-year-old field.

Wax deposition in producing wells is one of the most challenging flow assurance issues which is worsened when not addressed during well design. EC-40 being the first and only well completed on reservoir X1.0, was completed without provisions for wax inhibition. It produced about 1,100BPD with intermittent mechanical wax cutting intervention every 6 months. However, as production continued, the start-up rate, FTHP and the duration of production continued to reduce thus increasing the frequency of the wax cutting until it became uneconomical. In this paper a combined approach involving the use of chemical solvent and a Wax Inhibition Tool (WIT) was used to remove and prevent wax formation. A Xylene – Diesel chemical solvent was used to dissolve the entire wax in the tubing and restore the well to production while the WIT which prevents wax deposition, was installed at the XN-Nipple of the tubing. The well was opened up to a potential of 1,000 BPD after successfully removing the wax and installing WIT and produced for about 4 months before getting waxed up again. This paper illustrates the lessons learnt from the case study and based on results proposes an optimized way of re-installing the WIT or a retrofit chemical injection valve for wax prevention.

Production ramp-up from aging assets poses several challenges, substantial oil gains and attendant learnings. The scenario for OML-42 was complicated by prolonged production shutdown, associated wells and facility vandalization occasioned by over nine (9) years shutdown by the former operator. Most wells were illegally operated and mis-managed by oil saboteurs during the nine years shutdown. On acquisition of OML-42, the new investor conducted sequential field Re-entry activities, facilities repair, wells revamp and aggressive production ramp-up campaigns in the fields within OML-42, to minimize Re-entry cost, optimize production and profit. This paper focuses on production ramp-up initiatives deployed in OML-42 fields to grow production from a pre-reentry rate of50kbopd to 70kbopd, without any rig-based activity. It also elaborates unfamiliar difficulties and learnings derived from the ramp-up campaigns.

Near wellbore impairment result from various factors such as mud invasion, filter cake deposition, and fines migration in producing fields. Micro Emulsion Chemistry, other than the traditional acid stimulation presents a new and novel remedial treatment for near wellbore impairment. A microemulsion is a typical Newtonian fluid system distinguished from emulsions owing to its being stable thermodynamically and self-organizing. This technical paper explains the process of candidate selection, data gathering, job execution, and resultant crude oil gain from deploying micro-emulsion technology (MET) on some strings in the Ogini and Isoko fields. The fields have different and unique challenges. While the Ogini field has characteristic heavy oil and viscous crude, the Isoko field has wax deposition challenges. Deploying MET treatment in both fields yielded record-breaking results and productivity (PI) improvements in multiple folds. A total of 3,500 bopd (incremental oil) was achieved from treatment on four strings in both fields.

The changing landscape of global energy and fluctuations in commodity prices have driven companies to get more efficient means to sustain their businesses. With companies seeking more from their assets via rigless interventions, the trend has been that the low-hanging opportunities have been executed. The opportunities left are either too complex for rigless interventions or the expected production is too small to make major-rig workovers economic. We discuss such complex opportunities that were revisited to ensure sustained production from mature fields. The first case study discusses a gas-lift opportunity that was suspended when tubing leaks were discovered. The three holes posed a challenge since they were quite shallow and not suitable to be used as the injection-point of the gas. The work-around was to use a tubing patch to cover the holes without significantly reducing tubing ID as much as a pack-off would to allow for future well re-entry. The second case study discusses a well with a tubing restriction that prevented perforation addition. The job stalled when a gauge cutter (similar OD as the available gun) barely passed through the restriction during a dummy run. Even if the gun passed through and was detonated, the expended gun would be swollen and irretrievable due to the restriction. A modified perforating gun that disintegrated upon detonation was used, eliminating the need to retrieve the expended gun. The third case study was a well completed with mud five decades ago. The mud had caked; preventing any chance of executing a poor boy gas lift. The solution was to adapt the cement-bond-log technique to identify regions of moveable mud in the annulus with the mud subsequently displaced out by pumping. The lesson learned is that opportunities that have stalled due to their complexity can still be executed via rigless workovers by leveraging on existing technologies with slight adaptations to create well-specific solutions.

Traditional quality management models and tools in recent times are giving way to integrated service quality models. These models check both equipment and personnel and operations optimization from the design stage, with one of the more recent innovations in this regard being the introduction of Agile Quality Management (AQM) in service quality operations. AQM, in a project context, is concerned with having the right processes to ensure both effectiveness (quality product) and efficiency (quality project). This paper presents the development of an AQM model for well delivery operations and the tools and techniques with which it was deployed successfully in a workover operation in the Niger Delta. AQM was deployed in six workover wells for OML 26 Asset as part of the Integrated project management of the well delivery process. The results of the model application in operations optimization are seen in the reduction of non-productive time (NPT) over the six-well campaign.

Production wells normally experience different phases of life, starting with the initial ramp-up phase after drilling and completion, through the plateau period and finally to the decline phase. The tail-end of the decline phase often present with intermittent production behaviors requiring ‘tender-loving care’ to maximize production performance. Wells normally quit in this phase of production and may require a period of pressure build-up before being re-opened to production. Primary reason for this behavior is increase in watercut or decrease in reservoir pressure or a combination of both. Typically, intervention actions on intermittent wells are based on initiation of artificial lift, water shut-off or production in a cyclic manner if there is no scope for these. The typical production cycle of a cyclic well goes from normal production through unstable production (fluctuating wellhead pressures) to eventually quitting. Whereas every naturally producing well eventually quits, paying close attention to operating conditions of cyclic wells can enhance their availability and unlock significant production volumes for the asset. SPDC, a Joint Venture Organization in Nigeria with oil and gas wells spread across the Niger Delta, has about 64 intermittent producers; 54 oil wells and 10 gas wells. These producers are approaching the tail-end of their lives and therefore produce in a cyclic manner-with uptime and downtime cycles. Driven by the desire to improve integrated production system capacity (IPSC), there has been a renewed focus on this category of wells towards improving their uptimes. An approach deployed to improve the uptime (availability) of these wells involved the optimization of well operating envelopes. This implied moving the operating points of the wells to the stable region of inflow/outflow performance curves after challenging the basis for the current operating envelopes. This led to the adjustment of choke sizes, increase/decrease of gaslift injection rates and relocation of chokes from wellhead to the manifold. Five pilot wells were selected for this project with operating envelope reviews carried out and adjusted based on detailed well performance analysis. The result is cumulative average uptime of 256 days versus historical cumulative average of 91 days (more than 100% improvement in uptime) for the 5 wells. The production gains achieved within a period of 3 months was over 50,000 bbls at no extra operating cost and no additional technical risk.

A significant challenge in the mature South Kuwait Burgan field is assuring maximum hydrocarbon flow through high water-prone sandstone intervals. Recently, water control or conformance treatments have been considered to make oil production from these reservoirs more economically feasible. This paper discusses the application of a novel downhole chemical methodology that has created a positive impact in overall productivity from this field. The production profile in this field has been challenging in terms of increasing water volume, which poses a great threat to continued economic viability and may lead to lower production rates, a reduction in recoverable reserves, and premature abandonment. Some of the production-gathering centers cannot handle the ever-increasing volumes of produced water and are operating beyond design capacity. In order to solve this challenge, a downhole chemical treatment was modified as a fit-for-purpose treatment to address the unique challenges of electric submersible pump (ESP)-driven well operations, formation technical difficulties, high-stake economics, and high water potential from these formations. A unique hydrophobically modified water-soluble polymer (HRPM) was implemented in a high water-cut well to selectively reduce water production. Because this well was producing with an ESP, the treatment was pumped down the annular space. A preflush was pumped ahead of the HRPM treatment to remove deposits that could prevent the polymer from effectively adsorbing to the rock surface. The treatment was then overdisplaced with brine. This technology incorporates an HRPM that is adsorbed on the rock surface, resulting in the alteration of rock surface characteristics. The hydrophobic modification to the base polymer chain adds unique associative properties to the system, which selectively reduce the water's effective permeability in the reservoir, impeding water flow and facilitating increased hydrocarbon flow. A direct result of the implemented treatment is that the post-operation well test and production data show a high sustained hydrocarbon production at a smaller choke size with significantly reduced water cut. This successful treatment confirmed the optimized conformance technology as a solution for the first well in this field. In order to achieve maximum reduction in water production, this technology is customized based on the temperature and permeability of the treatment zones, thus ensuring it is fit-for-purpose. Furthermore, this paper summarizes the candidate selection, design processes, challenges encountered, production response, and lessons learned from this treatment and can be considered a best practice for addressing high water production challenges in similar conditions in other fields.

Surveillance mapping is a reservoir management process first developed by Shell and Exxon for the Brent field in the UK North Sea. It involves an integrated reservoir-wide management process with the objective of not only understanding subsurface dynamics during production but also delivering a future work programme that will maximize reservoir potential. 1 Surveillance Mapping was recently deployed in candidate selection for Short Term Oil Generation and Work Over activities in the Zoom reservoir located in the Niger Delta area. The Zoom reservoir is an East West Trending anticlinal structure, predominantly shore face deposits with incised channels. The Zoom reservoir, which is a large structure, commenced production in August 1991 and 50MMstb of oil has been produced to date. Thirteen oil wells have produced from the Zoom reservoir. These wells were drilled in phases post updates of various development plans published in 2003 and 2010. Production performance across the reservoir started declining due to natural water encroachment, poor productivity issues, well and flow line sabotage etc. This triggered an aggressive strategy to identify suitable remedial action that would support the drive for resuscitating the wells in a cheap and safe manner. Five wells were identified as potential Short-Term Oil Generation candidates and have been executed successfully with good rewards. This paper will review the success story of candidate wells scoped from the surveillance map and its impact on the optimization of the reservoir potential.

The Well A14 was drilled in 2004 with dual completion and flowed for about 7 years. The well was shut-in due to high water cut and sand production. In December 2011, the well was re-completed single with 7’’ Cased Hole Gravel Pack and ESP + YTool. The well was later sidetracked and deviated to a tie-in point in order to encounter the target at optimal structural positions and provide additional drainage points on the target level to optimize hydrocarbon recovery from the field. The flowed for a period of 2 ½ years and stopped flowing as a result of electric fault on the ESP. Following this and the unfavorable price of crude oil at the time, there was need for an optimized means of intervention; several factors were considered and a HWO intervention using HWPU was selected. This paper addresses the contingent challenges faced and how these were overcome in the course of this 2nd W/O to recover the existing completion and run-in with a new design of ESP and accessories. During POOH the old completion after laying down the D-ESP packer on surface, the well kicked as a result of poor circulation during the killing operation. This resulted in a loss of control and fluid influx spilling to the environment. This challenge was addressed in compliance with the best standards. The W/O was resumed and the entire completion string and ESP assembly + Ytool retrieved. Subsequently during the final installation of the new ESP, the string parted at the threaded connection and the entire ESP completion assembly was lost in hole. This second incident was carefully reviewed by the team involved prior mobilization of fishing equipment and eventual recovery of the lost-in-hole in a single attempt. The entire completion containing the lost-in- hole, on about 2000m of 3 ½" Tubing completion was recovered; the new assemblies were prepared and RIH successfully. The well was eventually completed and currently flowing (≈2000bopd). The responsible team reviewed the incidents, identified lapses and proposed future procedures in order to forestall reoccurrence.

Recently, a multinational exploration and production (E&P) company identified an opportunity for production optimization in a shallow reservoir with the zone of interest behind casing and without using any form of isolation for completions. A major challenge during this operation was the engineering design, as this was the first time a catenary cement operation of more than 31.8 m 3 (200 bbl) of slurry would be pumped through coiled tubing (CT), in addition to the high well deviation (~79°) consideration for installation of the cement retainer. Additionally, insufficient deck space on the platform and load-bearing capacity to accommodate the intervention spread presented a potential derailer for the attic oil development. A rigless well intervention program was designed using a 1.75-in. (125K) CT catenary system unit, which could be installed on a barge. The system would allow better CT reach and a higher injector snub/pull capacity. CT was used to install the cement retainer, punch holes in the 4 1/2-in. tubing, and pump cement. A total of 34.6 m 3 (218 bbl) of 15.8-lbm/gal resilient slurry was pumped through CT, which was equivalent to pumping a cement volume approximately six times greater than the CT volume. This was necessary to place a 1056-m cement packer in the 4 1/2-in. tubing 9 5/8-in. casing annulus and place 200 m of cement on the cement retainer. The operation was successfully completed using CT, avoiding more costly rig options for recompletion of the well. Zonal isolation was achieved, and the bypassed reservoir pay was perforated with ~600 B/D production. This approach proved to be cost-effective, with savings of approximately USD 1.3 million, which was achieved without compromising operational and safety performance. Rigless recompletion has been a cost-effective approach for production optimization in mature fields. However, existing well architecture, access to bypassed hydrocarbon pays, and environmental characteristics present challenges for developing some of these reserves.

Well Intervention operations are carried out to improve production performance of a declining well, restore production to a well that quit, or improve well integrity, among other reasons. Well bore clean out and stimulation are two of the common well intervention operations done on producing oil and gas wells to improve performance. Well AA, a major oil and gas producer started to decline after three years of production, therefore a well bore clean out and stimulation exercise was designed to improve performance of the well. The first Intervention operation was planned after various crude sample and precipitate analysis reports showed organic deposits (wax and asphaltenes) in the well. Slickline drift also indicated a restriction in the tubing. The treatment recipe for the well intervention was designed based on laboratory test carried out on the crude and precipitate sample that showed an 85% dissolution of the organic deposits in Xylene and 55% dissolution in Solution Z (a mixture of Xylene and HCL). The 85% dissolution was considered adequate to ensure a complete wellbore clean out, with Solution Z planned as the contingent treatment recipe for any solid deposits not dissolved by Xylene. Contingent on the successful wellbore clean out, a matrix stimulation was to be done using an Acid preflush and Regular clay acid as the main treatment. But this operation failed because instead of resulting in an increase in production, the well couldn't produce to surface and had to be shut-in. This paper will review the problems encountered from the unsuccessful intervention of well AA because of the lack of a detailed recipe design to find the best treatment to dissolve organic deposits in the well and precipitates, as well as residues formed from the reaction between organic solids and inorganic acids. In addition, this paper will present the detailed work that went into designing the right treatment recipe for well AA that resulted in successfully reviving the well after the initial failed intervention operation to become a prolific producer of over 1500 stock tank barrels of oil per day.

The prohibitive costs & risks associated with performing PLT and potentially the isolation of the water producing zone through WSO in deepwater fields such as Akpo renders these operations economically unattractive. This paper addresses the application of analytical method including the use of 4D monitor results to replace conventional PLT to identify, screen and select viable successful water shut off candidates. Prior to executing water shut-off treatment programs, a combination of 4D seismic interpretation, production history review as well as the collection of completion and reservoir information were thoroughly performed to ensure that the wells are properly selected. Well's diagnostic plot (WOR and WOR′) must be consistent with the type of water coning or channeling problem identified from the 4D time lapse seismic and also the depth of possible mechanical plug must be around or above estimated current oil-water contact (COWC). Two candidate wells having 6-5/8″ SAS Slot 10 in 8.5″ open hole, at approximately 4,000 meter TD, and 82 deg C reservoir temperature were selected. The water cut values were 55% in one well and 60% in the other. This paper presents below the significant upside for WSO attributed to the use of analytical method and integration of 4D seismic data by eliminating the need to run a traditional PLT. The operation was technically & economically successful on one well with a decrease of watercut from 55% to 16% resulting in the well incremental oil production of ~3kbopd. Operation is planned mid 2019 for the second well

The sudden fall of crude oil prices starting from the end of year 2014 got many astonished, as the price of Brent crude fell from $110 per barrel to $27 per barrel early 2016. Oil and gas producing companies were coerced to reduce spending on risky and costly exploration and production projects. Without doubt, all attention will be focused on production optimization from brown fields through the use of different well intervention strategies as the only proved means to gain more by spending less. Oil price has improved, hovering around $70 to $81 per barrel, in this current period of low oil price, there is much reason to embrace different well intervention strategies to keep wells on-stream more commercially. Since brown fields account for over seventy percent of the world’s energy demands, there is the need to revitalize these brown fields. With advances in well intervention strategies, getting as much as possible from a brown field is becoming more and more feasible. Thus, this study aims to develop the best workflow to optimize production through the application of different well intervention strategies. The results from a mature field in the Niger Delta were used to analyze the improvement of production through different well interventions. Extensive analysis of production history/performance, review of petrophysical parameters, identification of some subsurface (down-hole completions/well deliverability) and surface (facilities) constraints were carried out. The field has eight reservoirs, twenty-three wells, thirty-eight strings out of which production optimization using well interventions were applied on seventeen of the strings. Eclipse dynamic simulation software, Prosper and Ecrin well-test software were used to build the necessary models and analyze different sensitivity scenarios before and after each well intervention.

In 2017, offshore North Africa, a well in a dry environment utilized a new application of e-line milling technology in combination with a specialized bit to mill out a failed flapper. This was the first time this special bit with the e-line milling toolstring was used to mill out a flapper valve in a dry environment. With this paper the author will describe the history behind the milling bit design, the actual operation and production improvements. A gas well experienced a malfunctioning 7"x 4.56" 13 Cr. steel downhole flapper valve. Due to several operational challenges including limited well site access and temperatures over 150°C, there was a need for an alternative solution to mill the valve and allow access below it to re-perforate the well. The operator's method of choice was an e-line tractor and milling assembly that had previous success in the same area in similar conditions. Furthermore, a new milling bit was developed that drastically reduces milling debris and eliminates potential fishing runs. Finally, heavier intervention methods like coiled tubing were not possible to mobilize because of the weather conditions plus the risk of reservoir damage if introducing fluids required to mill on CT After the completion of the milling phase of the operation, another run was performed to set an access sleeve in the milled-out flapper valve utilizing an electromechanical setting tool. This access sleeve ensured that entry/re-entry through the milled flapper valve would be easily accomplished each time. The installation of the access sleeve was confirmed by first running a drift to TD, followed by the perforating guns toolstring and re-perforating the well. Milling of flapper valves and other well bore obstructions on electric line offers a cost efficient alternative technology to existing methods. Furthermore, it provides HSE benefits and logistical advantages by reducing the amount of required equipment and personnel.