The reservoir was only 2038′ vertical depth. The

The 85′ well separation was principally based on the requirement that the shallow aquifer is cased off prior to well kick off, directional drilling and open-hole ranging. Total loss returns and dry drilling are very often encountered while drilling charged shallow aquifer.

It was likely that when returns are lost gas would start blowing at the surface as the hole is drilled. Because of that, the system was designed to divert the gas while drilling using a rotating head. Gas would be diverted out and burned. The reservoir was only 2038′ vertical depth.

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The surface casing had to be set at 1000′ to cover shallow aquifer and massive loss zone prior to directional drilling and open-hole ranging. Another problem was that personnel had to face with total lack of wellbore surveys. Bottom hole uncertainty required effective magnetic ranging and relatively close initial well proximity. Several conclusions can be made after successfully drilled the relief well and killing the Well 159 (Flak L.H. et al, 1995). ·         The plan for handling the shallow gas hazard using a rotating head and multi-bowl wellhead was very effective.

·         Sour gas was safely diverted and flared while drilling and casing of the charged zone. Directional drilling with tools with site adjustable bent housing motors and MWD systems proved to be very effective.·         Good borehole stability was achieved with the use of asphalt-treated lime lignosulfonate mud. No stuck pipe was experienced during the entire operation.·         The initial intercept and first well kill were not avoidable given the requirement for close proximity between the two wellbores at the top of the blowout reservoir. Plans must be made to handle this likelihood as were made here. It is unfortunate that communication could not be re-established even after milling a slot in the Well 159 casing.

Having a back-up plan to go for the blowout reservoir under 5” casing became very critical for the success of this project.·         Several other wells in Bahrain had the similar problems as Well 159 due to mature fields and external casing corrosion in uncemented areas of the production casing. A regular well monitoring is required.

 When relief well is used as the control method in underground blowouts, the key is gaining direct communication. Once it is gained, well killing is generally not very difficult.  1.

1                    Algerian underground blowoutIn December 2008, personnel at one Algerian well was faced with problem of influx and well control. 12 ¼” exploratory well was drilled at 11 516 ft in the Emsian formation and casing was set at 5 250 ft. A pit gain was observed and the well was shut in.

Recorded shut in casing pressure (SICP) was 570 psi. Sudden drop in annulus pressure to 325 psi indicated lost circulation. It was assumed that it was in Tournasian formation at 5 305 to 6 180 ft where severe lost returns had been recorded while drilling.

Pore pressure equivalent mud weight at the Emsian formation was estimated to 11.7 to 12.7 ppg and formation pressure equivalent mud density at Tournasian formation was estimated to 10 to 11.7 ppg. Assuming that well had losses at Tournasian, 11.

6 ppg mud was pumped into the casing annulus. The annulus pressure remained constant which indicated possibility of an underground blowout. To prevent annulus pressure from increasing beyond 1000psi, batches of 13,3 ppg were pumped periodically into the annulus. Shut in drill pipe pressure remained 0 psi, and drill pipe was periodically filled to avoid gas migration.  ·         Sandwich-kill attemptThe hole was displaced through both drill pipe and annulus, ”sandwiching” the influx to the lost zone. 11,6 ppg mud was pumped through casing annulus by cement pumps and 15,9 ppg kill mud was pumped into drill pipes by rig pumps. Operation was partially successful because annulus pressure was still 600 psi after mud was pumped. However, procedure confirmed that the bottomhole pressure and the pressure at the loss zone were higher than predicted.

Casing pressure started to increase but drill pipe pressure remained 0 psi until casing pressure reached value of 2050 psi then it also increased proportionally. Gas was bled from the casing annulus in order to keep casing pressure as low as possible.  ·         Circulation-kill attemptKill mud was pumped through the drill string to control bottomhole pressure and to circulate gas out of the well. Proposed kill mud weight was 13,3 ppg (there was no accurate value for the bottomhole pressure so the mud weight calculation was based on hydrostatic pressure and SICP without height of gas influx). When pumping started drill pipe pressure soon dropped to 0psi, so the choke had to be adjusted without any reference value for drill pipe pressure. The choke position was kept constant and adjusted only when casing pressure increases. The well was shut in when the rig run out of mud. During the mud buildup, temperature and pressure logs were run to the depth of the downhole motor in the BHA.

The temperature log showed disturbance around 5600 ft which is depth of Tournasian formation. The log response was interpreted as fluid movement. ·         Annulus-pressure-kill attemptThere was no reference for operating with choke because the drill pipe pressure was 0 psi. The decision was to keep casing pressure constant or allow it to decrease. Lost circulation materials were pumped. The losses decreased to zero when first LCM pill reached the thief zone. When losses were decreased to the minimum, the pump rate was increased and the choke was opened slightly to counteract the vacuum effect on the drill pipe. However, the mud level in the drill pipe dropped continuously.

When the choke was opened to 1/16”, casing pressure dropped more than expected. This made control of the influx from the Emsian formation difficult. The pumps were stopped and drill pipe pressure started to increase. An influx of gas appeared to migrate inside the string.  The well response indicated gas remained in the annulus, and integrity of the Tournasian formation was still low. The kill operation resumed. 12,1 ppg mud was pumped ahead of 13,3 ppg mud.

The 12, 1 ppg mud did not reach the Tournasian formation so the pressure in front of the weak zone at the Tournasian formation was minimized. Also, more LCM pills were pumped. Additional gas influx entered the wellbore while there were repairs on the mud gas separator.

When the pumping restarted, pressure peaks suggested plugging of the ports in circulation sub and no more LCM pills were pumped.  ·         Low choke attemptChanges in the annulus pressure after shutting the well indicated that there was still small amount of gas in the annulus. The ”low choke” method was used in attempt to control the influx from the kick zone at the bottom of the well while allowing the loss zone to deplete to a lower pressure. Choke pressure was hold equal or slightly greater than the last recorded shut in value while circulating as fast as possible. The choke pressure was casing pressure recorded at the beginning of the operation plus additional 200 psi safety factor.

12, 2 ppg mud was pumped into the annulus. Drill pipe pressure increased which indicated that gas entered into the string. The operation was stopped when bottoms up volumes from the Tournasian and the Emsian formation were observed at the surface. The crew prepared to reduce the annulus pressure. Operations resumed after the drill pipe was filled. The well was monitored and the casing pressure was bled off 100 psi to test communication between annulus and the drill pipe pressure. An unexpected increase of 200 psi in drill pipe occurred, indicating there were now two different systems partially isolated by one or more packoffs in the annulus. The choke was opened in intervals to bled off 200 psi and four intervals were needed to reduce the casing pressure to 500 psi.

it was decided to fully open the choke because it was difficult to keep the casing pressure stable. No returns were recorded at the surface. The pump rate was increased without result. Mud along with water was pumped down the annulus to compensate for the fluid level drop. Once pumping in the annulus stopped and the casing pressure dropped to zero, the blowout preventer was opened to monitor the well.

Because of possibility of pipe plugging, pipe was worked. The pipe movement was possible but rotation was not. The well was shut in when mud overflowed at the bell nipple.

The casing pressure increased very quickly to more than 3000 psi. the pipe pressure was increased from 1800 to 3500 psi when only 31 bbl of mud was pumped. That indicated that pipe was plugged. Also, the casing pressure did not show pressure changes so it was concluded that one or more packoffs were present in the annulus. To break the packoffs, mud was pumped into the annulus but it was unsuccessful.

The drill pipe was worked in attempt to free the drill string and a ‘lubricate and bleed’ method was attempted. The pipe was completely stuck and no circulation was possible. The operator abandoned the drilled section of the well.

The drill string was isolated with cement or mechanical plugs. The drill string was perforated as deep as possible to isolate the annulus using cement. After that, drill string was cut off.  Lessons learned (Aguilar P.M., 2011):·         It is recommended that an open hole formation integrity test (FIT) be performed after repairing the loss zone and regaining the circulation. This helps ensure the wellbore pressure integrity is equivalent to the FIT recorded at the last shoe depth.

·         If leak off occurs before the equivalent shoe FIT is reached, wellbore maximum allowable surface pressure and kick tolerance should be recalculated at the loss zone depth to accommodate the downgraded FIT. ·         If creditable formation pressure data is not available, the heaviest kill mud weight possible should be used.·         Training in kick detection and BOP shut in on all rigs is recommended.

The main lesson learned from this incident was the necessity for well-trained and experienced drilling crews and the importance of adequately sized mud-mixing and handling equipment. 1.  Conclusion Each underground blowout is a unique situation with no guaranteed standard solution. Rig personnel should closely monitor ongoing operations and existing producing wells for a sign of problems. In many cases, operators fail to recognize and respond immediately when an underground blowout occurs. That makes well control more difficult due to eroded flow paths, degradation of downhole tubular and supercharging.

There are many indicators that can help personnel to determine is it underground flow severe and does it require special control procedures. Location of the fractured zone has to be determined to be able to successfully gain control over a well. There are several control methods but every blowout is a special situation so with the careful observation the best method should be applied.


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