# Presentation: 289972

## The Case Historyof an Underground FlowOffshore Texas

- Developed by
- John Rogers Smith, P.E., Ph.D.
*Louisiana State University*
- Funded by
- Minerals Management Service
- U.S. Department of the Interior

*An Interactive Group Learning Exercise*

**Notes:**
Foreward:
This case history review follows the same course of events that led to the author’s understanding that an underground flow was in progress and to his  involvement in the team that corrected it.  Given that the author had also been involved in the mistakes that resulted in this condition, the realization that an underground flow had been in progress for over two months was a shock.  This review therefore begins with the evidence that caused that shock.  
The author first made this presentation to the American Association of Drilling Engineers’ “Advanced Well Control Forum” in New Orleans, Louisiana on April 3, 1991.  The presentation was subsequently adapted as a training exercise for rig crews working in the same field.  This adaptation as a formalized, interactive, group learning exercise was developed at the Craft and Hawkins Department of Petroleum Engineering.  It was funded by the Minerals Management Services U. S. Department of the Interior, Washington, D.C., under Contract Number 14-35-001-30749.  The contents do not necessarily reflect the views and policy of the Service, nor does mention of trade names or commercial products constitute endorsement or recommendation for use.   
The general objective of this training exercise is to demonstrate the importance of effective well control to both the cost and the safety of an overall operations.  
     - continued on next page

## The Case Historyof an Underground FlowOffshore Texas

- Developed by
- John Rogers Smith, P.E., Ph.D.
*Louisiana State University*
- Funded by
- Minerals Management Service
- U.S. Department of the Interior

*An Interactive Group Learning Exercise*

**Notes:**
Forward - continued:
It will give specific examples of 
how important seemingly mundane well control monitoring practices can be 
how important it is to make well-thought out decisions when performing well control operations, even when the situation is not severe 
the difficulties of off-bottom well control
how even severe loss of well control can be corrected with carefully designed, implemented and monitored operations.  

	John Rogers Smith, P.E., Ph.D                        		Craft and Hawkins Department of Petroleum Engineering		Louisiana State University				January 11, 2002

## Overview

- Begins during platform development drilling during 1980’s
- The real beginning a few months earlier
- Focus on “Turning Points”

**Notes:**
Introduction:
The case history can be used simply as a review told as an interesting and informative story.  However, these notes are intended to help the review leader to make the case history an interactive or “minds-on” learning exercise.  More explanation of how this can be used as an interactive exercise is provided in the report delivering this and other training modules to the MMS and in SPE#38605, “Case-History Based Training for Control and Prevention of Underground Blowouts,” presented by J. R. Smith (this author) and A. T. Bourgoyne Jr. at the SPE Annual Technical Conference and Exhibition in San Antonio, Texas, October 5-8, 1997. 
A script and questions are provided, where appropriate, in this section below each slide to guide the leader and participants.  The leader may select those questions for emphasis or detailed discussion that relates most closely to challenges and issues that may be faced in the participants’ future operations.  The answers are provided for comparison to the participants’ answers or for direct information if a given question does not warrant discussion.   The answers are intended to be valid for this specific event but should also be generally valid for reinforcing effective well control practices.  Additional factual and discussion material is included on the slides themselves.  
“Turning points” are the decision points where actions were taken that resulted in subsequent failures and successes.  

## Mudlog

**Notes:**
Script:  The story begins the way the author really learned about what was going on.  The sixth development well from the platform is being drilled and is approaching the intermediate casing point in the first pressure transition.  
Q:  What is typically the very first warning sign of a potential kick while drilling?
A:  Drilling Break.  See the beginning of a break at the bottom of the log.  But remember the first “positive” indicator is usually an increase in return flow, which is how this kick was detected.   
Q:  What is the significance of the increase in background gas at the bottom of the log?  
A:  It is gas that was circulated out after taking the kick.  

## Unanticipated Pressure

- Kill wt. mud
- 	=  mud wt. + (SIDPP/(.052 x TVD))
- 	=  9.8 + (600/(.052 x 8710’))
- 	=  ___________________
- Drill pipe stuck
- Required 13.6 ppg mud to stop flow
- Cemented drillstring in hole

**Notes:**
Script:  So a kick was taken at a depth near where the pressure transition begins in this area.  In itself that is nothing special.  
Q:  How significant is this kick?  Specifically, what kill weight mud is required.  
A:  12.2 ppg , a relatively “strong” kick.  
Q:  What’s wrong?  Specifically, what could have caused this kick and why did it take such a high mud weight to control it?  
A:  Could be any of the four standard causes of abnormal pressure:
	undercompacted sediments
	differential fluid density (unlikely, pressure too high)
	diagenetic effects
	fluid migration effects 
  We really don’t know at this stage.  
Q:  What should we do next?  
A:  The actual decision was to plug back and redrill a sidetrack while diagnosing what the cause might be.  

## Mudlogs 

**Notes:**
Script:  This section was normally pressured in the 5th well.  

Q:  Why is the 6th well different?   
A:  Don’t know, maybe different geology.  Geologists and geophysicists will check.  

## Unanticipated Pressure

- Moved well location
- Took kick 30’ shallower in same drilling break; shut in immediately; 3 bbl. gain
- Kill wt. mud
- = 12.6 + (800 psi/(.052 x 8680’))
- = 14.4 ppg
- (Note: Pressure at shoe exceeds the fracture pressure)
- Pipe stuck while working it through the Hydril
- Killed well with 14.4 ppg
- Cemented drillstring in well to plug back

**Notes:**
Script:  When  drilling the sidetrack, the well is shut-in immediately upon entering the drilling break as a precaution.  Kick size was small, the kick is even stronger and harder to control than before.  

Q:  What is going on?  
A:  Let’s think about the possibilities again.  

## What's Wrong Here?

- Geologic Possibilities
- Pressures higher in section due to being in different fault block
- Pressures shallower than offsets due to missing stratigraphic section
*Neither geologic possibility was supported by either geological or geophysical data*
- Man Made Possibilities
- Pressure transfer in offset well
- 5th well was one of the following:
- closest offset
- had seen this section normally pressured
- had a major well control problem deeper

**Notes:**
Script:  No geologic evidence exists for any of the geologic causes, but man made fluid migration is a possibility, i.e. an underground flow is possible due to having a major problem in the previous well.  

## Reaction

- Establish ad hoc, multi-disciplinary team *including division operations manager and assigned essentially full time to this problem*
- Drilling Engineers
- Drilling Supervisors
- Production Engineers
- Log Analysts
- Re- enter 5th well
- Clean out to TD
- Run logs:
- temperature
- noise
- cement bond
- pulsed neutron
- Check annulus pressures

**Notes:**
Script:  The author was one of the drilling engineers assigned to this team.  The decision was made to diagnose whether an underground flow in the 5th well was the actual cause.  

## Temperature Log 

**Notes:**
Script:  This temperature log was run in the 5th well.  

(Option to use as statement or as question depending on audience and intent.) 
Q:  What would cause a temperature log to look like this?  
A:  Flow from the objective reservoir at about 13,800 feet up hole to the previous casing shoe at about 11,700 feet.  

## Noise Log

**Notes:**
Script:  The noise log shows much higher than background noise for several hundred feet below the 9-5/8” casing shoe.  

Q:  Why?  
A:  Probably gas flow exiting the annulus of the well and causing fracturing of formations below the 9-5/8” casing shoe.

## Cement Bond Log

- “Free Pipe” From 11900’
- (170’  Below 9 5/8” Shoe) To 14100’

**Notes:**
Script:  Cement bond log confirmed that the primary cement job did not isolate the objective reservoir from shallower formations as intended.  

## How Did We Get In This Shape?

- Let’s review the “Well Control Problem” in the 5th well

**Notes:**
(Note:  just read slide.)  

## Well Plan

- @ 11730' MD · 11407' TVD

- Fr. Gr. = 18.7 ppg

- = 11092 psi

- 8-1/2" Hole

- BOP's 10,000 psi WP

- 7,500 psi Test

- 13230' MD · 12892' TVD

- 13630' MD · 13292' TVD

**Implications:**

- 1. Similar to four previous successful wells

- 2. Maximum possible SICP  = 9723 psi

- 3. Kick tolerance = Gas Kick of 670' ~ 22 bbls

- TD @ 14250' MD · 13911' TVD

**Notes:**
Script:  The 5th well was drilled using a very similar well plan to the previous four wells.  These wells were all very high pressure gas wells.  The formation pressure at the top of the objective gas sand was equivalent to 17.7 ppg.  The formation fracture pressure at the previous casing shoe was 18.7 ppg.  Consequently, there was a small, but adequate, margin between taking a kick and losing returns in these wells.   
(NOTE:  See notes on wellbore slides for additional detailed points of information or discussion.  The 22 bbl limit on gas kick volume that can be shut in on without losing returns and the casing design pressures are important considerations to remember.)  

## Slide 15

**Notes:**
Script:  One of the differences in this well plan was to run a 7-5/8” instead of 7” production liner.  

Q:  Will running the larger O.D. liner have any significant impact on well control?  
A:  It will increase surge pressures during running and ECD during circulating therefore increasing the risk of lost returns.  

Script:  The decision to run the liner with less clearance ultimately resulted in lost returns that were not experienced or not severe in previous wells - a turning point decision.  

(NOTE:  See notes on wellbore slides for additional detailed points of information or discussion.)  

## Slide 16

**Notes:**
Q:  What happened while running the liner?  
A: See notes on wellbore slides.  Lost returns when tried to circulate liner.    

Q:  What happened that can be the cause of a kick?  
A:  Lost returns.  

Q:  How could you monitor the severity of lost returns and risk of taking a kick? 
A:  Monitor displacement with trip tank while going in the hole.  Measure volume of mud required to fill hole if not staying full while running or circulating.  Fill hole with water and measure volume if won’t stay full with mud.  Calculate loss of hydrostatic pressure due to water replacing mud.  Observe if water begins to flow back indicating a kick.       

 (NOTE:  See notes on wellbore slides for additional detailed points of information or discussion.)  

## Slide 17

**Notes:**
Script:  Approximately 400 bbls of mud and cement were lost to the open hole while cementing.  

Q:  Why is this important to maintaining well control?  
A:  Indicative of severe lost returns.  Cannot tell whether hole is staying full.  As shown on slide, if fluid level drops 140’, a kick would result.    

Q:  Why is filling the annulus important when returns are lost?  
A:  Helps avoid loss of overbalance as cause of kicks.  Gives indication of whether overbalance has been lost and allows the well to be checked for flow (you can’t see flow if the annulus is not full until the kick refills the annulus.) 

(NOTE:  See notes on wellbore slides for additional detailed points of information or discussion.)  

 Script:  Decision not to monitor lost returns was potentially a turning point due to not rapidly identifying a kick.  

## Slide 18

**Notes:**
Q1:  What caused the shut-in pressures?  Kick or trapped pressure?  
Q2:  If you don’t know, how could you tell? 
A2:  Bleed small volume through choke and recheck pressure.  Pressure stayed   the same or increased slightly.    
A1:  Pressure not bleeding off means this was a kick.  

Q:  See question and answer on slide about causes.  

Q:  How would you try to control?  What do you think would happen?   
A:  Any of following alternatives -   
Set squeeze tool and squeeze liner top (OK, original contingency plan), 
Implement circulation to kill with  driller’s method (What else?), 
Leave well shut-in and let cement set (OK, good if no gas migration), 
Strip back in hole to kill (Can’t, running tool on pipe and flow is outside liner),   
Lubricate (No point, no gas at surface yet)
Volumetric control (OK, if done properly) 
Bullhead (Probably no point, gas kick is below casing shoe)  

Script:  So, let’s see what really happened.  

## Slide 19

**Notes:**
Script:  Since there was already kill weight mud in the well, the decision was made to circulate using the driller’s method to remove the gas from the well under control.  The author was one of several off-site advisors who accepted this decision.  Knowing that this was ultimately not successful, we should question this decision.  

Q:  Is bottom hole pressure being kept  constant?
A:  No.  

Q:  If not, why not and what will happen?
A:  This only controls the pressure at the bottom of the drill pipe.  

Let’s see what happened.  

## Slide 20

**Notes:**
Script:  A full well volume (from the running tool up) has been circulated during the attempted kill.  Casing pressures were increasing faster than expected.  The “low choke pressure” method was tried to minimize casing pressures.  Now, casing pressure is very high.    

Q:  What is the “maximum allowable surface pressure before formation fracture?  What is probably happening downhole?  
A: MASPBFF = (Fracture Grad - Mud Wt.) x .052 x TVD
= (18.7 - 18.0) x .052 x 11,407’
=___________________ Therefore with 18 ppg mud filling the annulus, it would be 415 psi or much less than the current pressure.  
    Lost Returns

Q:  Why are surface pressures so high?  What would have prevented this?  
A:  Gas entering the well when underbalanced, especially during “low choke pressure,” caused the loss of mud hydrostatic and the high SICP and SIDP.  Stopping circulation and shutting in the well when pressures began increasing significantly would have delayed or prevented excessive pressures.    

CONTINUE ON DUPLICATE FOLLOWING SLIDE

## Slide 21

**Notes:**
CONTINUED
Q:  Is the high SICP a problem?  
A:  Yes, “maximum allowable surface pressure” based on casing burst pressure of 8150 psi is only 5705 psi.  

Q:  Why is the SIDP = 1150 psi?  
A:  The well is essentially filled with gas from below the running tool to the depth of the gas reservoir.  This should have been recognized as implying that an underground flow was in progress, but at the time, it was not recognized.   

Q:  How would you try to control or just reduce excessive pressures?  What do you think would happen?   
A:  Alternatives -   
Set squeeze tool and squeeze liner top (Can’t, SICP too high to work tool) 
Implement circulation to kill with  driller’s method (Not again) 
Leave well shut-in and let cement set (Is cement good?  Won’t reduce SICP) 
Lubricate (Maybe, but too slow to have much effect)  
Volumetric control (Won’t reduce SICP) 
Bullhead (Can reduce SICP if can pump at fast enough rate at high pressure) 
Dynamic kill (Requires design, not really applicable when shut-in and pipe above depth of lost returns.  Bullheading more appropriate.)  

Script:  Let’s see what was done.   

## Slide 22

**Notes:**
Script:  See notes on slide.  Bullheading should have overdisplaced the gas from the annulus with mud.  Gas has apparently entered the drill pipe, but SIDP and SICP are much less worrisome than before bullheading.  Ask class to note that CP = 1400 psi on the 9-5/8” by 11-3/4” annulus. 

Q:  How much mud volume was needed?  
A:  Ideally need enough mud to overdisplace annulus to minimize final pressure and displace gas.  (4-1/2” by 9-5/8” annulus volume  600bbl.)

Q:  The situation has improved, but what does the CP on the 9-5/8” by 11-3/4” annulus mean?  
A:  This pressure should be zero and is another indicator that there may be underground flow in progress.    

Q:  What should be done next?  The original contingency plan was to squeeze cement in the liner overlap.  The lower SICP means that the squeeze tool could be set to do this.  How would this help the overall situation?  
A:  If successful, it eliminates the risk of a surface blowout, allows gas to be removed from inside the well without risk of another kick, and maybe more. 

Script:  Let’s see what happened.     

## Slide 23

**Notes:**
Script:  Review liner top squeeze operations and resulting implications on slide.  The final squeeze pressure implies that gas was displaced from the work string and the section of the well between the end of the work string and the lost circulation zone, that cement reached the lost circulation zone, and that the fracture pressure of the lost zone controlled the shut in pressure at the end of the squeeze.    

Q:  What next?  
A:  Wait on cement to set.  Bleed off drill pipe pressure.  Circulate the gas out of the annulus.  

## Confirming Recovery

- No flow from well
- Cement tested to +3000 psi
- Dressed off liner top cement and tested to +3200 psi for 30 min.
- Test liner top with water cushion in stages to –2300 psi ~14.5 ppg EMW for one hour
- Ran liner tieback
***Turning point :***
- No attempt to confirm that probable (in hindsight) underground flow had been stopped  or that pressure source on 11 3⁄4” x 9 5/8” annulus was shut off.

**Notes:**
Script:  Pressures reduced to zero.  Liner top squeeze tested as described on slide.  Cover lower half of slide until end of discussion.  

Q1:  Are we really finished?  (Encourage discussion) 
Q2:  What could we have done to be sure?
A2:  Should be obvious: check CP, run temperature log, and/or run noise log for indications of flow outside the liner as well as testing the liner top and casing for leaks.  . 
A1:  Not really but see next slide.  

## Recovery

*Now we are back to where we started the review:*
**What are we going to to do to stop the apparent on-going underground flow?**
- Kill it?
- or
- Bridge it?
**Can we kill it?**

**Notes:**
Script:  Read slide.  

A:  Let’s look at the author’s calculations to answer this question.  

## Flowing Bottom Hole Pressures For Dynamic Kill

**Notes:**
Script:  This nodal analysis plot shows that the rate of dry gas flowing from the productive formation to fracture pressure at the loss circulation zone could be as high as about 300 MMSCF/D.
It also shows that pumping 18 ppg mud at a rate of 5 bpm down the work string, through the bottom of the liner, and into the liner annulus would cause an increase in bottom hole pressure above formation pressure regardless of mixing with any rate of gas.  Consequently, it would stop any further gas flow into the well and displace the pre-existing gas into the loss zone.       
These calculations were made using conventional pressure drop calculations for two-phase flow with a computer program.  Now (‘2002) there are special computer programs to do this specifically for well control and relief wells that could make more reliable predictions.  

Q:  Is there an accepted way to predict whether bridging would be successful or to insure its success?  
A:  Not that the author knows of.  

Script:  So let’s see what happened.  

## Slide 27

**Notes:**
Script:  Read operations summary on slide.  

The bond log showed cement bond at the base of the gas reservoir, but no bond at the top.  The other logs showed indications of improvement but not conclusive elimination of flow behind the liner.    

Q:  So the inside of the well is still safe, but the underground flow may still be in progress, what should be done next?  
A:  There ultimately needs to be a successful cement job to eliminate risk of a recurrence of the underground flow and to provide adequate zonal isolation for production.  

Script:  Let’s consider what might be done to achieve a successful cement job.     

## Slide 28

**Notes:**
Q:  How should this remedial cementing be done?  
A:  Perforate and squeeze above the cement at the base of the sand.  

Script:  A conventional cement squeeze was attempted, but there was no squeeze and a CBL showed no bond even though tracer showed the cement did go up the annulus between the liner and the formation.  

Another squeeze was tried with similar results.  These were time-consuming because the cement had to be drilled out of the inside of the liner and then a CBL run to evaluate the results.  The liner would then need to be perforated again before another squeeze.  

A more effective “squeeze” method was adapted that over-displaced the cement through the perforations and then held it in place.  This allowed successive jobs to incrementally fill the enlarged annulus and diagnosing the cement effectiveness by testing the perforated interval.  If the test pressure was less than the fracture pressure at that depth, another over-displaced cement job was done.  This continued until a squeeze was observed during a job.  That job was terminated without over-displacing the perforations and drilled out and tested as for a conventional squeeze.  

## Temperature Log

**Notes:**
Script:  A temperature log was then run.  It shows that flow from the gas reservoir has been effectively stopped.   

## Noise Log

**Notes:**
Script:  A noise log was run and shows that noise levels in the interval below the casing shoe are equal to the background noise levels.  Therefore the noise log also indicates that the underground flow has been stopped.  

## Cement Bond Log

- Before
- “Free Pipe” from 11900’
- (170’ Below 9 5/8” Shoe) To 14100’
- After
- Cement with some bonding to both pipe and formation from 13200’ to 14100’ (Throughout major gas sand)
- 20’ cement seal at top of gas sand (where multiple “Squeezes” were performed)
- Some additional cement up to 12950’ (Confirmed with tracer)

**Notes:**
Script:  Finally another cement bond log was run.  It shows that the gas reservoir has been isolated with cement to prevent a recurrence of the underground flow.  

Finally, this story is coming to an end.  The loss of reserves has been stopped, and the risk to this and adjacent wells eliminated.  The utility of the well was preserved, and it was subsequently completed and was still on production as this is written over fifteen years later.  

## Phase 

**Critical Issue**

- Planning

- Risk of lost circulation with tight

- clearances not mitigated

- Avoidance

- No record of displacements

- Detection

- Poor, hole not kept full

- Reaction

- Good, shut-in when flow seen

- Control

- Poor, squeeze plan not followed,

- Driller’s method improperly applied

**Original “Kill”:**

- Loss of Control

- Not identified

- Recovery

- None – only isolated

- Confirmation

- None

**Second Kill:**

- Loss of Control

- Inferred by kicks, logs confirmed

- Second Recovery

- Planned, evaluated after each step

- Confirmation

- With comparison to baseline logs

**Notes:**
Script:  This case history provides examples of many of the important factors in maintaining effective well control.  These key learnings include:  
Kick detection while tripping in the hole requires that displacement be monitored with a trip tank. 
Kick detection during lost returns, as occurred while running and cementing the liner, requires that the hole be kept full and that the volume to fill the hole be recorded. 
Avoiding lost returns while running and cementing tight clearance liners requires special design of equipment, fluids, trip speeds, and circulating rates to minimize surge and ECD effects.  
Even small kicks can result in major problems if improperly handled.  
Off-bottom well control requires special procedures to control pressures below the end of the drill string. 
Bullheading kick fluids back into open hole formations does not insure that a kick has been successfully killed.  
Possible underground flows outside pipe require diagnosis by methods other than pressure inside the pipe.  Examples are temperature logs, noise logs, and surface pressures on outer annuli.  
Even severe, long-term loss of well control can be corrected with carefully engineered, implemented, and monitored procedures.