Safety, efficiency, and reliability are at the forefront priorities when it comes to planning and executing drilling and completion operations. As an industry moving toward exploration and development in far more demanding environments and is consequently driven to find new and innovative ways to optimize drilling and well completion costs; The integration of RFID technology into the oil and gas industry is an excellent approach which has resulted in reduction of risks, operating time as well as increased operational flexibility. The use of RFID technology as a technique for remote actuation of downhole drilling tools has proven to be very effective over the conventional mechanical (ball-actuated) drilling tools enabling operators to run multiple remotely activated drilling tools on same drilling BHA while also maintaining full through-bore ID. Radio-frequency identification (RFID) provides a game-changing solution across a broad range of disciplines to maximize efficiencies and reduce operating costs significantly. This paper reviews a field application in which an RFID-actuated circulation sub was deployed in a multiple-assembly tool string to drill and simultaneously log a 6-in. hole section for a well in Karachaganak field. The risk of downhole losses in a 6-in. horizontal section (∼1,200-m length) in Karachaganak field led to separate drilling and logging runs. The main driver of adopting RFID technology in this application was the inability to retrieve a logging-while-drilling (LWD) radioactive source (RA) and also pumping high-concentration lost-circulation material (LCM), should downhole conditions dictate activation of a circulation sub. RFID-enabled circulation sub to eliminate additional trips of the LWD tool, as the previously deployed mechanically-actuated circulating sub would not allow access to the LWD RA because of its limited post-activated inside-diameter (ID) size. This requires additional time for tripping operations to change out the BHA in case of downhole problems, such as stuck pipe and total loss scenarios. Introducing RFID-enabled tool provided full through-bore access enabling RA retrieval while keeping the option for multiple activations of the circulation sub as per operational requirements thereby enabling the operator to immediately eliminate the additional trip for the LWD tool. In this case study, no downhole losses were experienced; however, the RFID circulation sub served to boost hole cleaning once total depth was reached as this operation required high fluid-circulation rates for efficient cuttings transport, especially in the avalanche zone of the well. Additionally, the full through-bore flow provided by the RFID-actuated sub enabled the client to displace the well with a high flow rate and therefore save significant time and costs on fluid displacement The adoption of RFID-actuated circulation sub improved drilling performance by enabling the operator to complete the entire operation in a single run and saved 4 operational days. The main objective of the system was to drill and log safely and efficiently to the target depth in one run and achieve high flow rates to enhance wellbore cleaning.

Pre-salt carbonates in the Pre-Caspian Basin have prolific hydrocarbon-bearing formations onshore and offshore. Recent exploration wells more than 5000 m deep in the region have had limited success, mostly due to challenging conditions for well testing. This paper summarizes key elements of one of the first successful drill stem testing (DST) campaigns in Ansagan Field. The holistic DST design for Ansagan field addressed perforating methods, brine selection, packer and DST equipments material selection for hostile environment with high-pressure, high-H2S fluids, and corrosive acid to be used for stimulation. The surface equipment design had to reliably control the well, separate fluids, measure flow rates, and dispose hydrocarbons with minimum environmental impact. Surface flow rate measurement combined of a multiphase flowmeter and three-phase separator. Downhole samples were collected with a single-phase reservoir fluid sampler. Calcium & zinc bromide brine with 1.77-SG density proved effective. The specially modified completion packer design was in the well up to 6 months and was successfully retrieved after the test. Although perforating in these deep high pressure wells was usually performed on wireline, accurate shock prediction and design adjustments managed the risk for using tubing-conveyed perforating (TCP) to perforate large intervals in underbalance conditions allowing to achieve lower skin, and flow the well immediately. The DST string enabled performing production logging, downhole fluid sampling, and acid stimulation with coiled tubing. Fluid sampling was performed on wireline to preserve gas condensate components at reservoir conditions. The highly accurate memory gauges, real-time operations, and reservoir engineer's support made it possible to acquire accurate data to characterize the fracture distribution, which is vital information in fractured carbonates. In summary, three wells have been successfully tested with a total of 16 zones at Ansagan field, achieving all well test objectives.

The team evaluated multiple options for conformance control, with the primary focus on shutting off water. The team broadened the focus to include gas shut off, as well as implementation in the sour gas injection wells, and the water injection wells. The new completions have become the preferred completion for most of the wells. The conformance control packer assembly is selected based on the openhole caliper logs, pressure measurements, drilling breaks, fluid saturations and the thickness of the reservoir intervals. After the drilling rig runs the completion, the wells are completed with a coiled tubing unit. The coiled tubing tools and procedures have improved since the initial swell packer completions. Many of the new wells use smart coil with embedded fiber optic cable to help ensure a successful completion. The swell packer completions have been very successful as a whole, but not every swell packer is effective in isolating between layers. The Distributed Temperature Sensing (DTS) has been very useful in identifying both leaking packers, as well as communication between zones from within the reservoir. There are several benefits of using the swell packers for mechanical diversion of stimulation fluids. Without the swell packer completions, the average treated zone was 500m thick. Initially, most conformance control completions consisted of three to four packers. Since then the average number of packers has increased to five to six packers per well. Most stimulation treatments now target an interval of less than 100m. There have been several major rig workovers (MRWO) in the sour gas injection area of the field. Comparisons pre and post MRWO well performance indicate that the swell packer improved the productivity of wells. This paper shows how the swell packer completions have helped to reduce unwanted fluids and enhanced the oil production capability of the wells. It will describe the selection process for packer placement, and the success rate of these packers. The paper also covers the evolution of the coiled tubing procedures that helped to make the conformance control program a success.

Wastes injection when implemented correctly allows reducing environmental impact and in many cases reducing projects costs. However, often such projects suffer the support from regulators, local communities as well as have little interest from technical professionals. The goal of the paper is to reduce the fear of wastes injection by sharing the acquired experience on waste injection project challenges and opportunities. The paper describes subsurface aspects of wastes injection projects in stages of feasibility and implementation, performed by operator for the offshore area in North Caspian Sea and onshore area in western part of Kazakhstan. The operator investigated several wastes injection opportunities in different time. Drill cuttings injection (DCI) was studied for two locations in the past and a pilot DCI project was successfully implemented in 2013-2014. Wastewater injection possibilities were studied for onshore locations for water injection from processing facilities. Currently the operator is pursuing the project, which will allow using a DCI well for the injection of wastewaters generated offshore.

Operated by BP Exploration (Caspian Sea) Limited, Azeri-Chirag-Gunashli (ACG) is a giant field located in the Caspian Sea, Azerbaijan. Primary pressure support in the ACG field is achieved by water injection into co-mingled reservoirs completed across Fasila and Balakhany horizons. There are different types of down hole completion across ACG's water injection well stock; in some of those a permanent fibre optical cable is installed recording continuous DTS (distributed temperature sensing) data throughout the well life. Limited 4D seismic resolution, restricted access to the wells, a high cost of intervention and a time limitation for extended logging programs means that, in most cases, temperature in combination with pressure transient and well performance data are the only surveillance data that can be used for understanding and control of injection conformance. This paper discusses multiple case studies using the integrated approach and methodology for temperature data acquisition and interpretation to control water injection conformance over the life of the ACG field. There are many factors that affect the quality and accuracy of temperature log data which have been well described in the industry, hence these will not be looked at in detail in this paper. The paper will describe the importance of the multi-disciplinary teamwork required for a comprehensive logging program to ensure the most accurate and representative temperature data are acquired. The paper also discusses the process of planning and execution of a temperature data acquisition program, together with real field examples of qualitative evaluation of water injection conformance. The integration of the acquired temperature data with other static and dynamic surveillance data allows the operator to make critical decisions on water injection management.

Integrated production data management system (PDMS) solution is presented that incorporates three remote locations of the company's different departments (Field Operation, Engineering and Economics) into a single working environment. Automated workflows implemented on the basis of PDMS aimed to improve speed and efficiency of engineering analysis and economic planning. PetroKazakhstan Kumkol Resources JSC operates a wellstock consisting of more than fifteen hundred wells. Operational data is loaded into a system on a daily basis at a central office on the field site. At this stage data is quality checked and used for production monitoring. All information is automatically synchronized to the office in Kyzylorda city, where production back allocation is performed. Every month regulatory reports are generated from the system. Decline curve analysis forecasts at well level are frequently applied for daily routine economical assessment of well intervention and surface construction operations. Moreover, saved forecasts are also automatically available for budgeting purposes in Almaty office. As a result of integrated PDMS solution, PKKR JSC engineers and economists get easy and automated access to raw operational data as well as results of allocated production and forecasting by the decline curve analysis (DCA). Automated workflows for back allocation, regulatory report generation and forecast result data sharing made different departments closer and decision making more efficient. Overall, data travel distance of about 1500 km. Shared workspace with standard analytical templates (plots, reports, maps, forecasts) allowed engineers to promote best practices across organization, align reservoir surveillance and monitoring approach in a common standardized way. PDMS allows engineers, previously overloaded with manual data handling and reporting, to have more time to solve reservoir and production engineering problems. Meanwhile, the economists gain direct and automated access for DCA forecasts, performed by reservoir engineers, not only at field, but also at well level. This helps prioritize each well's economic potential and rank accordingly, which is critical in budget planning. The novelty of integrated PDMS solution is that it brings a new level of integration of different departments into synergy. Teamwork spread beyond engineering, operations and geology, adding economists into the team to address today's operational challenges.

The Caspian offshore is a promising area for hydrocarbon accumulation. Since it is an offshore, it is a challenging area in terms of strict environmental regulations and safety. At the early stage of the project it was clear, that reservoir properties of the exploration well require artificial lift assistance to produce during well testing. Therefore, designing proper DST string with artificial lift was crucial to the success of well testing. This paper describes the methodology to select the artificial lift solution for well test. It shows the unique combination of technologies and techniques that enabled a DST with ESP in combination with the Y tool, that provides capabilities to run thePLT below the pump. Also, one of the main challenges of well testing operation was to handle heavy oil fluid at surface. Being in environmentally sensitive area, designing a surface well testing equipment in a limited footprint, that enables efficient separation and disposal of heavy oil was very critical. Another challenge was unconsolidated formation with the high risk of sand production under drawdown, therefore downhole testing string and ESP pump supposed to withstand large quantity of solids during the production. The key technology that enabled testing was a new generation of abrasion resistant ESP pumps, that are designed to handle extensive solids production. The heavy oil also posed a number of risks. The surface equipment was specifically designed to heat oil in the tanks and if required to mix with diesel before flaring operations. Local regulation does not permit production during the night time and allows limited number of days for well testing. Therefore, well testing design must enable to acquire all necessary information within short period of test duration. The real-time data transmission and interpretation was a key to achieve main goal of the testing in exploration well - to accurately characterize the reservoir. This was the first successful ESP-DST in Caspian Sea. Despite of many challenges, the technologies that were selected for well testing operation was proven to be reliable. This allowed Operator to untap previously not accessible hydrocarbon reserves.

Development of the Kashagan field is very complicated and encounters many challenges, such as a harsh offshore environment with an ice season, highly pressurized wells and a high H 2 S concentration (sour). All these challenges were known during the field construction phase, but after one year of production, another unforeseen challenge emerged– severe downhole scaling in certain oil producers, flowing at very low water cuts (<0.5% water). Scaling is a widespread and well-known phenomenon in many, often mature fields around the world, but it was not expected to occur in Kashagan in the early stage of field life. Well scaling developed very fast, leading to almost 50% productivity reduction on several wells in a few weeks time. Wellbore scaling put Kashagan production plans at risk, so it was critical to remediate the affected wells as soon as possible. A multi-disciplinary team started work to address the issue. For most "brown" fields, remediation of wells affected by scaling is a routine job. In the case of Kashagan, which had just started production, downhole scaling was a big challenge for various reasons. Firstly, when rapid productivity decline was observed on some wells, it was not clear what caused the impairment, and a lot of investigative work was done to identify the nature of impairment and root cause (mechanism) behind it. Secondly, scaling badly affected D-island wells, where SIMOPS well intervention capability is highly restricted. D-island is a hub for offshore processing and gas reinjection facilities, located just few hundred meters away from wells, and any well intervention requires the creation of a "yellow zone" and causes significant production deferment. Thirdly, it was clear from the beginning that remediation is a temporary measure, and that it was important to progress from "firefighting" mode to impairment prevention mode, for all wells. Despite all complexities of the task all affected wells were successfully brought back to production and, after various successful anti-scale treatments, fine-tuning of the scaling prevention process is currently ongoing. Due to the scaling, multiple processes had to be improved, such as metering, wells testing, wells surveillance and well interventions. In the design phase of the project, a well intervention was considered as something extraordinary, and expected to happen rarely, primarily for well integrity issues, not for scaling issues. Well intervention operations became a more routine operations and have started to play a critical role in the integrated activity planning process. This paper describes how Kashagan wells were affected by wellbore impairment and what actions were made to remediate wells and to return wells to its original productivity.

Significant progress in technologies development of well completion and stimulation allowed to involve in the development of reserves which 10 years ago were considered unpromising due to the too low reservoir permeability. Particularly significant influence of modern achievements on shale beds, which were previously not seriously considered as possible objects for hydrocarbon production. The success of shale oil production in the United States inspires oil companies around the world to study the possibility for the development of such objects. On the territory of the Russian Federation is perhaps the largest area of shale formation of the world – Bazhenov formation. In 2016, PJSC Gazprom Neft for the first time for the Bazhenov formation implemented a full cycle of construction of a horizontal well with a Multi-Stage Fracturing, which on the level of the applied technological solutions is not inferior to the American analogues used in the United States for shale oil production. The length of the horizontal section of the well was more than 1000 m; the 114 mm liner OD was run in and cemented. The cementing operation was carried out with liner rotation, and the cement blend itself contained specially selected additives which were designed to ensure high resistance of the cement stone to the damaging effects from multi-stage fracturing. The experience in drilling and cementing, completion and production operation of the well turned out to be positive, and in 2018, a pilot project started drilling a whole series of horizontal wells with multi-stage fracturing at two well sites. During the implementation of the project was found a stable relationship between the well production and the efficiency of fracturing, which is significantly affected by the isolation the anulus.

Conventionally, for an oil development field with the risk of water breakthrough during its life time of production, a cased hole with perforation method will usually be chosen. This is a proven method of completion strategy that enable an effective way to provide proper water isolation. Project B is an oil development project in Malaysia with 3 wells in total, which were drilled and completed by early February 2019. During the early stage of the project at Front End Planning, offset well data suggested that there are 2 target zones of hydrocarbon in the field being separated by a thin layer of shale (3meters), dividing them into upper and lower lobe of oil reservoir. It was expected to see a water reservoir below these two reservoirs and hence, the proposed completion strategy was to perform Cased Hole with Perforation and Gravel Pack. Further studies between Production technology and Completion team had raised the concern on the integrity on the water isolation due to the shunt tube system used for the gravel pack job. To effectively isolate cross flow between the upper and lower lobe of the oil zone and delay the water break through from the lower water reservoir section, project team modified the completion strategy from Cased Hole Gravel Pack to Open Hole with Stand-Alone Screen (OHSAS). Hybrid Swell Packers will be installed at the thin shake layer to provide the zonal isolation. The completion strategy modification had simplified not only the offshore completion operation, but also the logistic planning and footprint allocation due to lesser equipment required. Total cost saving had been achieved at USD 1.44 Milliom with around 2.4 days reduction on completion operation timing. This paper will discuss the rational to modify completion strategy, cost comparison and operational sequence between these 2 methods of completion. This paper will also cover the challenges, limitation to deliver the well.

The Chirag platform is one of six BP operated platforms to produce from the Azeri-Chirag-Gunashli Field in the Azerbaijan sector of Caspian Sea. The Chirag platform was scheduled for early oil delivery but was not developed with any means of artificial lift and as the field became mature, wells experienced water-breakthrough. In the absence of artificial lift, wells can typically flow naturally up to 20-40% watercut at steady-state conditions, however restart of these wells is challenging and at some point, impossible. Historically high watercut (20-40% and above) Chirag wells were side-tracked to up-dip dry oil leg. However, sidetracking for this reason could be uneconomical and could leave reserves from main production sands unrecovered. Therefore, enabling artificial lift for Chirag wells is vital. Several artificial lift options were evaluated, including ESPs and Jet Pumps. The most attractive method proved to be Gas-lift. In the absence of surface facilities to provide gas lift injection into the wells, using high pressure shallow gas formation as a source for gas lift was identified as suitable both from technical and economical perspective. This project was the first of its kind implementation in BP and offshore Caspian. A number of technical challenges had to be solved to deliver the project: Selection of continuous and permeable gas bearing formation Optimum gas lift valve size selection Sand production from perforated shallow gas formation Plant constraints to start-up and produce the well with AGL Three formations were selected as a potential energy source for gas-lift supply. It was identified that among all three zones only one is continuous (confirmed by reservoir pressure data in the Chirag area), with a good rock properties and adjacent to a field operated by the National oil company SOCAR with long production history. The gas lift valve size was selected to deliver enough energy to continue producing the well at high WC (>40%), minimize depletion in gas formation and lessen shut-in cross-flow of the lift gas. Perforation and down-hole completion were designed to minimize likelihood of sand production from gas formation, and in the case of sand production limit erosion of downhole equipment. Thorough risk evaluations were carried out to enable start-up of the well with high shut-in tubing head pressure which was due to high reservoir pressure of gas formation and its cross-flow to main production sands. This paper will focus on describing the technical evaluations carried out to assess and solve the challenges presented above and compare current performance of the wells' vs predicted. As of today, two Chirag wells are operated with AGL and one well has AGL capability for future implementation. The AGL project is confirmed to be a reliable mean of artificial lift method for Chirag wells assuming limited depletion in shallow gas reservoir.

This paper describes the design and operational performance of the 15 kpsi Shah Deniz Stage 2 completion clean-up surface process equipment which has been designed to ensure solid/debris-free gas/condensate production at first gas in 2018. This project demonstrates a genuine step change in the design and operation of well testing and clean-up systems. It takes process safety to a new level whilst simultaneously reducing the overall equipment footprint, compared to traditional well test systems. The design brief for this project included a requirement to safely process and correctly dispose of all fluids produced from completed SD II production wells. This included formation hydrocarbons at elevated flow rates, completion fluids and residual drilling fluids. The surface package also had to fit within the rig well test deck and individual skid weights kept within the rigs crane capacity. As a result, the decision was made to design, engineer and manufacture a customized set of equipment. Additionally, an upgraded data acquisition system was required to process the increased volume of data as well as provide the required level of system monitoring and control. An enhanced process shut down system was also needed in order to implement the shut down philosophy demanded by the projects process safety policies. The SD II completion installation schedule, in which twelve wells were completed back to back, called for a semi permanent installation of the surface process package. This provided the opportunity to implement many of the design upgrades described in this paper. As a result of these upgrades operations have been carried out in a safer, more controlled and efficient manner, whilst simultaneously maintaining full compliance with all industry and company specific regulations. The two central elements to this operational efficiency was due to the surface equipment operating well within its design envelope, even at high flow rates, and the data acquisition system enabling the entire process system to be fully monitored and controlled. This enhanced process control enabled emerging risks to be rapidly detected and mitigated prior to any detrimental escalation. This paper discusses the various challenges posed by the project and the ways in which these were mitigated and overcome. Many of these design solutions can be applied to future high flow rate surface systems.

Well commissioning operations offshore encounter multiple organizational, operational and technical challenges that must be safely overcome to efficiently deliver high-quality service. Coiled tubing (CT) perforation and commissioning performed in hostile reservoir conditions and high pressure is one of the most complicated multiservice operations, especially in a sensitive aquifer ecosystem like the shallow Caspian basin. A comprehensive approach used to deploy an innovative solution to the challenges provided experience in such operations and lessons learned. An innovative perforation technique was selected for the project: electric-line-enabled CT for precise depth control in combination with an advanced gun deployment system for conveyance of long gun strings under pressure. New techniques were incorporated to improve equipment efficiency and reliability: detonation shock-resistant bottomhole assembly, two independent emergency disconnects, software to predict and evaluate shock load and dynamic underbalance, high-pressure H 2 S-rated and conventional connectors for a specialized tool deployment stack (TDS), rounded scallop guns, and high-tensile CT logging-head-disconnect weak points. To date, more than 10 well commissioning operations were successfully completed with this innovative method. Integrated service project management was a key approach to achieving successful results by effectively integrating multiple service lines. The technique proved to effectively minimize operational time, associated risks, improper equipment use, and interface failures between different service lines. The developed solution is a seamless integration of electric-line-enabled CT, the CT logging head, the gun deployment system for pressurized well conditions, and a set of wireline tools and specialized perforation equipment. The design was optimized to perforate the well in three or four runs at overbalanced condition (squeeze mode) in one rig-up job instead of the more than 20 wireline runs typical in conventional operations. Additionally, the use of CT provided the flexibility to perform pumping operations for well displacement, injection of an H 2 S scavenger, and stimulation, as per the operator's plan, without or with only partial rig-down. This was the first time that integrated service project with the described CT perforation technique was performed in the Caspian region. The acquired experience will facilitate design, preparation, and execution stages for such type of jobs with multiple services involved.

New wells in KPO are completed as multistage frac completions utilizing up to ten stimulation sleeves activated by a ball landed in a respective seat (called a baffle) installed inside the sleeves. The objective since the beginning was to mill balls and baffles in the horizontal section improving the safety of the operation while minimizing volume of fluid injected, execution time, costs, and clean-up time. The initial approach was to use coiled tubing. Using coil to mill balls and baffles was not optimal, as the milling performances were difficult to replicate well after well. Additionally a significant amount of fluid was injected into formation together with some debris causing formation damage and making clean-up a long and costly process. An alternative option of milling utilizing robotic technologies was investigated as a viable solution for improving our performance. Therefore, the experience gained by KPO on milling with tractor in multistage frac completion is unique worldwide, and did add a lot of value to the wells delivered to production. This paper describes the evolution and modification done to tractor milling approach, particularly: Yard tests performed before implementing the operation in the field. No field deployment application took place before yard test outcomes were completely satisfactory. Results of the tests and modifications done to the tools as a result of the tests performed in the yard. Performance during field job execution, lessons learnt during each application, and how those lessons learnt influenced design modification of the tools and milling methodology. Thanks to a close collaboration established between KPO and Welltec, all objectives were accomplished with repeatable performance. Recently, up to nine balls and baffles corresponding to the entire horizontal section have been milled with a tangible benefit in terms of production, reducing clean-up time and emissions and improving safety. Even though the initial target was achieved, KPO believes there is still room for improvement and optimization. This will be done in the near future following further dedicated yard tests with positive results.

When one of the production levels becomes so thin, that oil production using existing methods is unprofitable, it is better to operate it at the expense of the energy of a thicker formation. It requires development of new equipment capable to perform this function. In addition it should be noted when one of the reservoirs is depleted, maintaining of production level at the expense of other reservoir energy is urgent and may reduce the cost per one ton of produced products. To this end, a set of advanced equipment has been developed to operate these reservoirs. Designed setting allows operation of a low-powered upper bed at the expense of thicker lower reservoir energy. The new layer is operated by submersible, and the top one - by jet pumps. For this purpose, an advanced special-purpose packer has been developed allowing simultaneous wellbore and pump cable sealing. Products are blended and come to the land surface of the well along the central channel. The unit has a special design back-pressure valve to prevent displacement of top layer products under more powerful lower pressure.

The Azeri-Chirag-Gunashli (ACG) is a giant field located in the Caspian Sea, Azerbaijan. The field is operated by BP on behalf of Azerbaijan International Operating Company (AIOC). Wells are drilled and completed penetrating multilayers of weakly consolidated sand with low unconfined compressive strength. The typical sand-face completion is Open Hole Gravel Pack (OHGP), Stand Alone Screen (SAS), Expandable Sand Screen (ESS) and Cased and Perforated (C&P). After a period of time, when a well does loose it's sand control integrity, the wellbore has the potential to fill up with sand and create a production deferment. A viable option to revive these wells is by cleaning the sand out of the tubing to gain access and perforate the upper-zone. This paper describes the success story of a challenging sand clean out and return to production in one of the wells in the ACG field. The job utilized an integrated clean out system from downhole to surface. A hydraulically actuated, switchable circulation sub was used with a real time downhole measurement system. While running into the well, forward jets of the sub helped penetrate and suspend sand and while pulling out of the well, the sub was switched to a low resistance, backward jetting mode which sweeps sand more efficiently. Adding real-time downhole measurement to the system enhanced the performance of the sub ensuring it was functioning correctly as per plan. A sand monitor was used in the surface return line to continuously monitor the returned sand. Design software was used to support the operation from start to finish and real time data comparisons to the software predictions created additional assurance of safe operational steps. Following the successful cleanout, the plan was to isolate the lower sand producing zone and perforate the well across a higher oil bearing zone. A live well deployment system on electrical coiled tubing was selected to perforate over 300m of the pay zone in a single run. This system was selected due to its capabilities of deploying and reverse deploying the extra-long perforation guns with positive wellhead pressure and completing the job in one run. Combination of the electrical and mechanical features of the coiled tubing added additional value to the operation as it made it possible to correlate depth based on CCL and gamma ray, displace kill weight fluid to base oil to create underbalance conditions and monitor the well pre and post perforating with CT in the wellbore. The intervention was successful and the well was put back into production. This case serves as a reference for future sand clean outs and CT conveyed live well perforation jobs in the region.

Electro-hydraulic robotic tools that perform well interventions on electric line (e-line) have come of age over the past 10 years and can now be used to accomplish tasks previously done with the use of jointed pipes and/or coiled tubing conveyance system. Examples of such tasks are downhole milling, shifting of stimulation sleeves, etc. Surface real time monitoring and control features are required to ensure that such tasks done by robotic tools are successfully achieved with high accuracies. As the demand increases to use this type of powered devices in a more hostile well environment, service companies have developed technologies to expand their operating range. Starting from late 2013, the robotic technology solution has been used in KPO horizontal sour wells to close stimulation sleeves when required for reservoir fluid management, to convey perforation guns, to convey production logging tools and to mill frac balls and ball seats. This paper will present four case histories of the robotic technology application in the Karachaganak field. It will discuss the advantages of the technologies, the challenges and the future improvement required to further optimize the field operations.

Concentric Coiled Tubing (CCT) was introduced in early 2014 to the Caspian Sea in the Azeri Chirag Gunashli field as a solution for sub-hydrostatic wells where sand cleanout techniques are not feasible with conventional methods because of circulation losses and poor offshore nitrogen logistics. A number of oil producer wells were successfully cleaned out using CCT prior to the technique being deployed on a water injector well for first time. This study considers the first CCT cleanout of a water injector well. In addition to cleaning sand from the well, the following main criteria were identified during the planning stage of the job; reduce wellbore contact friction inside the protective coated tubulars, minimize the number of CCT runs and fully displace heavy brine for a lighter friction reduced fluid. Job data collected during the initial runs was used for simulations with proprietary modeling software in an attempt to minimize pipe to pipe contact friction. A comparison based on the impact pressure at the nozzles with the available BHA's was also made from different scenarios simulated in order to best tackle the problem of any hard packed sand bridges in the well. This paper looks at how the above was achieved and also discusses the operational aspects of the job where proprietary BHA components and Coiled Tubing (CT) techniques were combined to break through a sand bridge described as the "hardest fill ever experienced in the field" by the operator. A combination of intelligent CT, rotating jetting tool and a specialized switching cleanout sub was quickly mobilized alongside the planned CCT midway through the operation when the hard packed sand was discovered. Once the hard packed sand bridge had been completely removed, CCT and vacuuming technology were once again used across the perforated interval to establish a clean wellbore and injection into the reservoir. This paper is a case study and summarizes the main planning and operational steps of the successful cleanout job and provides some guidance for future operations.

The electronic Permanent Downhole Gauges (PDHG) has traditionally been used in the Karachaganak field to monitor downhole pressures and temperatures, for reservoir management. The overall performance and quality of the data from some of the Permanent Downhole Gauges (PDHG) installed in the Karachaganak field was not satisfactory. Hence, fibre optics has been investigated as an alternative technology due to the reliability, calibration and cost concerns related directly to the Permanent Downhole Gauges (PDHG). This paper will discuss the implementation and installation of the first fibre optic pressure and temperature monitoring system installed in the Karachaganak field. A dual fibre optic pressure and temperature system (rated to 200°C and 20Kpsi) was installed to a depth of approximately 5000m with a maximum inclination of about 35°. The metallurgy for the fibre optics system was Inconel 718 due to the presence of H 2 S. The surface equipment comprised of a Zone 2 rated Wellhead Data Acquisition Unit which has direct connection to the operation base providing ‘real time’ pressure and temperature updates (up to one second update rate). The paper will highlight some of the design and implementation considerations that were addressed to combat issues which had been experienced with more conventional monitoring systems such as reliability, accuracy and data communication issues. It will also describe the process that was undertaken to meet the stringent Kazakhstan Metrology requirements that are required to be obtained prior to the deployment of a subsurface measurement system. This process involved meeting the requirements for GOST-K for Safety and Quality and the Metrological Certificate which ensures that all measuring instruments are of stated accuracy and resolution and are acceptable to an accredited Institute of Metrology. It will discuss the detailed Factory Acceptance Tests (FAT) and System Integration Tests (SIT), as part of the critical planning process prior to the field installation. The paper will also cover the challenges during installation and subsequent use. The deployment data interface requirements and associated benefits during well stimulation, well testing and subsequent production will be described in full.

The control line for CZ-5 well became plugged due to contaminants in the hydraulic control line fluid. As a result, CZ-5 well remained shut in with the deferment of 2000 bbls/day. Remedial solution was planned and it involved the installation of subsurface controlled safety valve or storm choke. Since the failed subsurface safety valve is in the jammed close position, the mechanism to lock open the flapper and to keep the valve open permanently must be done before the installion of the storm choke. The special tubing with smaller ID, or better known as straddle, was then set across the flapper and hang inside. Without the realization that the pressure setting of the storm choke calculation would become complicated with the smaller tubing/straddle inside, the closing and opening pressure were determined based on NODAL Analysis. The flapper of CZ-5 ScSSV was also expected to dislocate severely and a special flip open tool is designed to position the dislocated flapper back to its housing. Flapper flip open tool is the in-house designed tool that can be run using slickline for 2 7/8″, 3½″ or 4½″ tubing. This unique tool has enabled many lock open jobs in our operation and it has totally eliminated the need for flapper milling. The unexpected outcome of valve closing pressure and operating speed was experienced for a few times after the installation, causing the multiple intervention work to retrieve and to re-set the storm choke with different setting pressure. Though all minimum data required to design the storm choke for CZ-5 has been rightly considered, its performance is still very unpredictable and shocking. Determined to make the valve to work properly for a desired certain period of time, all operational data were gathered and studied. During the last rectification attempt, the storm choke has finally worked as intended. The paper will describe more on the challenges encountered during the set-up of flip open tool and modified straddle, the engineering design of both of them and the storm choke unique behaviour from the experience at Caspian Sea Operation.