Cairn Oil & Gas, Vedanta Limited has implemented full field Polymer Flooding in Mangala Field and is currently injecting nearly 400,000 bpd of polymerized injection water with average polymer concentration of ~2500 ppm. Partially hydrolysed polyacrylamide (HPAM) Polymer is mixed with source water to create a mother solution of 15,000 ppm concentration at Central Polymer Facility (CPF) and is distributed through a pipeline network to 15 well pads where it is diluted to achieve a viscosity of ~30 cP for injection. Artificial lift in Mangala is either by Jet Pump or Electrical Submersible Pump (ESP). In producers, a wide range of polymer concentrations are observed in the produced brine. Maximum polymer concentration measured is ~972 ppm and average polymer concentration is ~280 ppm. Recently, during well intervention activities, it is frequently observed that polymer like waxy deposits are obstructing the free movement of wire-line tools. During jet-pump redressing, polymer deposition was observed in the Body X-over (Reservoir liquid path), check valve assembly, throat and spacer nozzle to throat inside jet-pump. In addition, an agglomerated polymer substance was also observed in the slick line tool string. A general observation is that after a jet pump change, production rate increases sharply followed by rapid decline. This requires Jet Pump Change Out (JPCO) job at regular intervals (every 20 days in few wells). Furthermore, semi soft to hard polymer deposits have been observed in surface facilities i.e. injection water booster pumps, injection water filters and heat exchangers. Laboratory analysis of the samples collected indicated that the deposit consists of Hydrocarbon, Inorganic Scales and polymer agglomeration. Based on further studies it is observed that the degree of hydrolysis of the polymer deposit significantly increases between 50-80% in Jet pump deposits and up to 90% in heat exchanger samples. Increasing degree of hydrolysis reduces the polymer cloud point below reservoir temperature and heat exchange skin temperature. Solution to the problem can be identified by controlling the degree of hydrolysis in fresh polymer below 25 mol% and cloud point greater than 120°C, addition of scale inhibitor to the system upstream of scale formation, removal of deposit with a combination of oxidizer and chelant; other options continue to be studied.

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Raageshwari Deep Gas field is a relatively deep (2800-3500 meters) unconventional volcanic reservoir with pressure and temperature of ~ 5200 psi and ~ 140 degC respectively. Wells were completed as 3-1/2" Monobore producers and plug & perf method was used for fracturing stimulation. 3-1/2" 10000psi rated millable bridge plug was installed immediately after the fracturing stimulation which were then milled by coiled tubing based milling tools to clean up & test all the zones commingled. During milling of bridge plugs, substantial amount of gas along with significant condensate was produced from the zones, which resulted in vast variance in Coiled tubing circulating pressures and well head pressures. As a consequence, WOB was increased, in an effort to speed up the milling process. Unfortunately this resulted in frequent motor stalling and inefficient milling. Also, managing large amount of produced gas and condensate, along with milled cuttings, sand, gel and water, was an issue with regards to conventional surface equipment’s and frenzied flaring of condensate in vicinity of other gas producing wells. This paper describes how the bridge plug milling process was optimized over the course of the campaign of hydraulically fractured gas wells. This optimization included all aspects of the milling operation such as, WOB, penetration rate, milling fluid system which facilitated the increase in frac fluid recovery, as well as the differential pressure across the motor. This optimization reduced the bridge plug milling time to between 30 and 45 minutes. It also summarizes the challenges which had to be overcome during the successful implementation of this technique and the lessons learnt in due course of time. This paper also describes the use of a sand catcher along with the conventional surface well testing unit and an inventive surface rig up which not only assisted in perfectly managing the milling cutting, sand, gel and water at surface, while completely eliminating the requirement of flaring the condensate. The technique helped save about 5% of the total well cost well by reducing the number of days required for milling operations and the associated daily rental of surface well test and Coiled tubing spreads. This technique also ensured minimum flaring of hydrocarbons and faster hookup of wells to production facilities and therefore is strongly recommended in high condensate gas wells located in environmentally sensitive locations with HSE and economic concerns.

Various sand control completion techniques have been applied to address sand production issues in Field A. The sand production challenges are often aggravated with decreasing reservoir pressure and increasing water cut due to fields maturity. Conventional gravel pack methods such as circulation pack or high-rate water pack were effective and has high reliability in controlling sand production. However, these methods often resulted in high initial skin (subjected to gravel sizing, completion fluids, screen sizing, etc.) which affect the well productivity. For wells with fines migration issues, the skin will further build-up as the well produce over time. In addition, these sand control methods are associated with higher installation cost. In order to address these issues, Resin Sand Consolidation technique was successfully applied as primary sand control in Well 8 to prove its reliability, productivity, and cost effectiveness. It was the first application for a new development well in Field A and second in PETRONAS Carigali Sdn. Bhd. (PCSB) Malaysia fields (first implementation in 1998). This paper explains the detailed workflow from candidate selection to execution, challenges, and results from this successful pilot. There were three reservoirs completed in Well 8. The perforation strategy utilized 4 SPF 10/350 degree phasing self-gravitated oriented perforations which was executed under dynamic underbalance conditions to achieve optimal perforation tunnel cleanup. The perforation interval was kept short (< 10 ft) to ensure uniform treatment. One of the key steps in achieving successful resin placement is formation injectivity. Acid was pumped and injectivity tests were conducted before and after pumping to assess the effectiveness of acid treatment. The data acquired from the step rate test was used to determine the Fracture Closure Pressure (FCP) and Fracture Extension Pressure (FEP) where it will define the maximum pumping rate during the sand consolidation treatment. Identification of maximum pumping rate is crucial to ensure optimum displacement of resin into the formation during execution. Pre-acid injectivity results showed poor injectivity in all 3 reservoirs with treating pressures recorded more than the MASTP limit to reach pumping rate of 2 bpm. Near well bore damage removal treatments were executed using mud acid (15% HCl + 1.5% HF) followed by post-injectivity test which showed improvement in treating pressures. By the end of the operation, a total of 68 bbls of treatment fluid was successfully pumped into all three reservoirs. Well tests acquired during unloading and production phase have shown good results exceeding the target rate set during FDP with no sand production observed. It is expected that this new way of sand control for new wells could contribute towards reducing sand production issues in Field A while at the same time provide an incremental gain in oil production. The success of this pilot would open-up more opportunities in PCSB and other operators towards the implementation of similar sand control method for new development wells.

Objectives/Scope The Raageshwari Deep Gas Field in the western India, operated by Cairn India Limited, is a tight gas laminated reservoir (~0.1mD) with gross pay of ~700metres having numerous but small packets of good porosities and high gas saturations. This paper describes the holistic approach used to cover the maximum net pay of the laminated volcanic rock using the limited entry technique of fracturing with limited number of frac stages. It also summarizes how the conventional temperature logging practice post injection tests helped cover the net pay, improve and verify the limited entry technique, decide the number of frac stages and calibrate frac model. Brief discussion also includes the results of production logging used to access the reservoir response to stimulation. Methods, Procedures, Process The fracturing jobs were conducted through 3-1/2″ Monobore completion with target depths at ~3400m TVDSS. The challenge in developing a multilayered thick tight volcanic gas reservoir using the conventional single interval per stage perforating is that it would require more than 10 independent stages to effectively cover the available net pay which was deemed to be uneconomic. Limited entry Technique was used to combine number of sand packages in a single frac stage with high potential sands selected based on the reservoir and completion quality. Though fracturing simulators indicated theoretically that all of the perforation clusters which had different stresses and petro-physical properties, received pad and slurry to create a productive fracture, but verification was required. The effectiveness of the diversion was verified using a combination of Step rate/Step down tests, post mini frac/frac temperature surveys, post treatment pressure matching and time lapsed production logging. Results, Observations, Conclusions Limited Entry Technique has proved to be a cost effective method of increasing net pay coverage and EUR per well with minimum number of frac stages. Post SRT/mini frac/frac temperature surveys proved to be a very reliable, efficient and cost effective method for determining which perforations were taking fluid and the fracture heights which were generated. The heights obtained from the temperature surveys along with the pressure data/DFITs, were used to calibrate the hydraulic fracturing simulator. Also the production logging is showing the contribution form the all the targeted sands. Novel/Additive Information The application of limited entry technique, its verification using conventional temperature surveys and production loggings and the various operational and engineering learning acquired during planning to execution phase is an innovative and integrated approach in itself to exploit multilayered deep gas volcanic reservoir. Also pumping schedule modification like conducting step rate/down test in the pad sage or multiple step down tests in the same frac job were conducted while perforating individual interval/cluster