Minutes of morning meeting (Draft for editing) 12-April-2018 Suggestions & Recommendations by Mr. Balasubramanian

Tbg Corrosion Issues during Production phase of the Well

i) Tubing size: We are using mostly 2 7/8” tbg in 7” casing. The velocity of gas is high near the surface due to expansion factor of gas. The present tbg size is chosen (?), keeping in mind the end of the life condition of the Well. We need to plan a strategy.

Strategy-1: As long as there is no produced water produced, the tubing size is immaterial, and 3 ½” tbg is advantageous over 2 7/8” tbg. When water cut starts, gas rate reduces, and water loading tends to subdue the Well. To reduce the effect of Water-loading and prolong the two-phase flow life of the Well, we can use 2 7/8” (lower) x 3 ½” (upper) tapered string, fom the beginning also.

Strategy-2: Complete the Well with with 3 ½” tubing to start with. Declare the Well sick when water-cut increases beyond set limits (instead of allowing the Well to die down due to water loading and dead on its own) and move in the Rig. Do water shut-off & bring the Well back on production. Go for 3 ½” string or 3 ½” x 2 7/8” tapered string or 2 7/8” string depending upon the W/over results.

Tubing Grade: We should use tubing & casing of same grade as far as possible. L80 is preferred over N80 or P110. If tensile load is a constraint, going for higher ppf tubular is preferable instead of higher grade tubular.

Tubing material: We must look at the metallurgy of the tubing considering 30% CO2, 60000 ppm saline formation water. Carbon steels (irrespective of grade) are susceptible to CO2, H2S & Chloride attacks. We need to consider the costlier CRA (even then corration rate can be reduced, but not nullified) or go for CS tubing with corrosion and scale inhibitor dosing. From economics point of view, CS with corrosion inhibitor shall be considered o start with.

Tool-joint: To minimize erosion-corrosion, induced by changing flow-velocities, tubing with uniform cross-section shall be considered, either integral-joints (eg: Hydril jts) or metal-t-metal seal joints with no cavity at tool-joint (ex: Vam tbg).

Considerations during Drilling phase of the Well: “Hole to the Gauge” shall be our goal to achieve during the drilling phase of the Wells. Exposure Time & drilling mud have been discussed, as below:

Reduced exposure of the Reservoir Section to drilling fluids: We need to reduce the time we take to drill the reservoir section. Reduced exposure will reduce mud-cake thickness and so reduce the chances of differential stickups. Also formation damage due to invasion of drilling fluids will be less.

Reduction of exposure can be achieved by adopting a 3-casing policy, with the 3rd casing (the production casing/liner) covering the reservoir section of the Well. The mud weight can be adjusted (reduced) to suit the reservoir pressures, avoiding the risk of sloughing/caving related issues of upper sticky-shales.

Oil Base Mud: Oil base mud needs to be considered with caution when drilling thro’ gas reservoir as it introduces third phase (oil) near the wellbore apart from water and gas. This will further affect adversely, the near wellbore permeability. Water based mud system with suitable bridging material is more suitable for our reservoirs (as can be seen from the initial production rates of the producing Wells).

Use of CaCO3 as bridging / weighing material in drilling-mud, creates sticky cake against permeable layers, compared to barites, as opined by Mr.Hasan. However, from the near Well-bore effect point of view, emoval of CaCO3 is easily achieved by acid wash, while barites are insoluble in HCl. Different size/grade of CaCO3 suitable for our usage shall be identified.

Workover & Completion Fluid

Potassium formate is a worthy Workover & Completion fluid. It is non-corrosive as it has PH=9.5, non-damaging to the reservoir, and thermally stable at our reservoir temperatures. Also, the quantity required for preparing the w/over fluid is quite less, since most of our Wells can be workedover with fluid of Sg 1.04. Also, reuse of the Workover fluid can be adopted to reduced the Workover fluid cost. The effect of the interference of Potassium in logging needs to be discussed with our Logging Manager.

HEC derivatives as viscosifier & CaCO3 as bridging material shall be considered for controlling fluid-loss during Workover operations. (Note: Off the Self HEC is not suitable as such, since it is unstable beyond 120ºC).

Wells show poor influx after Workover job

The Wells generally cease to flow and show poor influx after the workover job. As commented by the field crew, the Wells do not flow again when ceased to flow, even before a rig job.

The reasons could be quite a few: (1)The introduction of Fe into the formation in the form of FeCO3, before w/over job, when no O2 is present (2) Introduction of FeCO3, FeO, Fe2O3 during w/over job with dissolved O2 introduced from Surface water (3) Introduction of scale particles before/during w/over job (4) Alteration of mineral equilibrium due to invasion of surface water (workover fluid) into formation which leads to the precipitation of salts, mobilization of fines etc (5) cumulative effect of all the above.

From the above, it can be seen that, formation damage is possible even before a Well is taken up for a workover job due to invasion of settling iron compounds & scale particles under favourable conditions. However, workover fluid introduced damage is within our control. The following prevention & cure strategies are for consideration and experimentation / implementation:

Damage Prevention strategy

(1) Declare a Well as Sick-Well, if the Well’s performance drops below set conditions and Kill the Well with Workover/Completion fluid using CT (2) Use clean mud tank & pumping system. (3) Use Potassium / Cesium Formate brine prepared with RO/fresh water as workover/completion fluid (4) Use suitable Oxygen-scavengers in the w/over fluid (5) For Fluid loss control use suitable HEC derivative as viscosifier and CaCO3 as bridging material (6) Use Packer completions while flow-back. (7) Flow back with controlled draw-down thro’ suitable chokes / adjustable choke.

Damage Cure strategy

(1) Choose a suitable Scale dissolving chemical – EDTA and derivatives (2) Device a methodology to treat the Formation by simulating reservoir conditions in the lab. (3) Soak the formation face / treat the formation, if required more than once (4) Flow back with controlled draw-down thro’ suitable chokes / adjustable choke.


  • Mr.Ajay Kalsi
  • Mr.Neminath
  • Mr.Prateek
  • Mr.Shabaz
  • Mr.Hasan
  • Mr.Balasubramanian