HPHT Well Design

NOVODRILL / ONGC / TRANSOCEAN HIGH PRESSURE DRILLING REFRESHER APRIL 2012 1. WELL CONTROL REFRESHER 2. HP/HT WELL CONSIDERATIONS 2.1 Well Designs Need for accurate shoe placement Loss and Kick potential 2.2 Equipment requirements and restrictions Higher pressures and temperatures Hydrates and the mud gas separator 2.3 Drilling Fluids Gas Entrainment Temperature Effects ( Static vs Dynamic ) 2.4 Operational Procedural requirements for HP/HT wells Fingerprinting, Flow Checks, Check Trips and circulating Kick Detection and Response 3. WELL TO BE DRILLED Well Design Discussions Problem Prediction and Response discussions 4. OPERATIONAL PROCEDURES TO BE USED 5. EXERCISES

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1. WELL CONTROL REFRESHER

WELL CONTROL CONCERNS ARE THE SAME AS FOR EVERY WELL TYPE CAUSES OF KICKS 1. NOT KEEPING THE HOLE FULL 2. SWABBING 3. DRILLING INTO HIGHER PRESSURES PREVENTION OF KICKS 1. KEEP THE HOLE FULL 2. DO NOT SWAB 3. BE AWARE OF INCRESING PRESSURE TRENDS PRESSURE TREND INDICATORS * CHANGE IN ROP ( positive and negative ) * 'd' EXPONENT * HOLE PROBLEMS * BACKGROUND GAS * CONNECTION GAS * TRIP GAS * TEMPERATURE DOWNHOLE * SHALE DENSITY * SHALE CAVINGS * DELTA FLOW * PIT GAIN IF IN DOUBT WE FLOW CHECK KICK INDICATORS * DELTA FLOW * PIT GAIN IF THE WELL IS FLOWING WE CLOSE IN THE WELL AND KILL IT KILL METHODS * WAIT AND WEIGHT * DRILLERS METHOD * BULLHEADING

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2. HP/HT WELLS - INTRODUCTION If a given rig and operation is deemed to be capable of handling conventional kicks then to determine the HP/HT requirement the differences between the two well types must be defined. The additional requirements / considerations for HP/HT over conventional well control can be summarised as follows:2.1

Well Design • • •

2.2

Drilling and Kick Handling Equipment • • • • •

2.3

Surface Pressures will be Higher Surface Temperatures will be Higher Downhole Temperatures will be Higher Greater Risk of Hydrates Influx Volume to be Handled at Surface is Potentially Greater

Drilling Fluids • • •

2.4

More Casing Strings / Stronger casings required? Formation Fracture Gradients Much Closer to Formation Pressures Rapid Changes in Downhole Pressure / Temperature

Heavier Higher Rheology to carry weighting material Different Influx Gas Behaviour in Oil Muds

Kick Detection • •

Dealing with Formation Charging Effects Quantifying Static and Dynamic Well Characteristics

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2.1

WELL DESIGN

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More casing strings / Stronger casings required? Most wildcat wells are designed to use a final hole size of 8 1/2" so that in the event of well problems a contingency liner / casing can be set and the well finished off in 5 7/8" or 6" hole. Most HP/HT designs will have the 9 5/8" / 9 7/8” or 10 3/4" or 7"casings being set in the main pressure transition zone. The selection of this casing shoe in the transition between normally and overpressured formations is critical

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Formation Fracture / Pressure Gradients The fact that these gradients get closer the deeper we go is well documented and impacts strongly on kick tolerance calculations. When a well is engineered certain assumptions must be made about pressures and strengths of formations. These can be right or wrong so the information we are gathering from the well as we drill it is vital to support or challenge the assumptions made.

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Rapid Changes in Downhole Pressure / Temperature These are common in HP/HT wells. On Wildcat wells , extreme caution must be exercised as the pressure transition can be as much as 3000 psi increase in only 70m. of drilled depth. At the same time that the pressures rise downhole then so do the temperatures. Increasing temperatures can be good indicator of rising pressure regimes. Only certain formations are capable of trapping such pressures. Typically these are Shales or Marls. They must be fairly plastic. They may have some porosity but it is unlikely that they will have any vertical permeability otherwise the pressure would have leeched away over Geological time. Typically again, as the pressure gradient increases then so does the water content of the shales. This can be spotted by two mechanisms. Firstly reduction in Shale density and secondly increase in background gas levels for a given ROP. For each foot drilled, more water is contained within the drilled cuttings. This water contains gas and as this gas is released at surface the background gas levels will rise. The skill required is to go far enough into the transition zone to get a strong casing seat but not so deep as to having the well 'blowing around your ears'.

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2.2

ASSESSING EQUIPMENT REQUIREMENTS

The salient HP/HT needs which will need to be met by this equipment are:• • • • •

Surface Pressure will be Higher – This implies the use of 15,000 psi BOP and Choke Manifold. It further implies the need for hydraulic assist to open and close valves when holding such pressures Surface Temperatures will be Higher – this implies the use of elastomers in the Standpipe, Choke manifold and BOP capable of functioning at temperatures in exces of 170 deg C Downhole Temperatures will be Higher – this means that the temeperature limitations of tools must be considered. The tools most exposed are LWD, MWD, electric logging tools and Jars. This could eliminate the use of coflexip hoses Greater Risk of Hydrates – this implies recognizing the potential for these then having procedures and equipment in place to prevent these from becoming a major problem Greater Surface Volume at Surface – This also implies recognizing the high volumes of gas that can be brought to surface . The main weak link in Rig equipment is the Poor Boy Mud Gas Separator.

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2.3.

DRILLING FLUIDS

The differences between drilling fluids for HP/HT wells as against conventional wells are fourfold. • • • •

Heavier Higher Rheology Different Composition to Provide Temperature Stability Different Influx Gas Behaviour in Mud

Gas Entrainment in the Mud Another problem that comes hand in hand with heavier muds is gas entrainment. Any gel strength which is sufficient to hold barytes will have no difficulty holding gas. This means that the mud will carry a residual amount of gas in it at all times. Typical background gas levels are one or two percent. One way to illustrate this phenomenon is to circulate the well after setting casing or a liner. Even though no new hole has been drilled, the gas detector will be showing some residual level of gas. In Production Tests the surface separation equipment usd to separate any gas out of produced oil will include a heater.The heater is used to heat the oil . As the oil is heated it gives up the dissolved and entrained gas much more readily. This phenomenon also applies to gas in mud. If the mud is hotter, it will release gas more readily . In a circulated well the temperature of the mud coming out of the flow line will not vary much during constant circulation. If the pumps are stopped at any time then the mud at the bottom of the well will heat up as heat soaks in from the surrounding rock . This means that any time that circulation has stopped there will be hot spots in the mud.These hot spots will give off entrained gas more easily than the constantly circulated mud and this will be picked up by the gas detector as an increase in Gas Levels. Care must be taken not to over-react to increasing gas levels from such situations. We expect that Connection Gas, Survey gas and Trip Gas levels will be higher than background gas levels . What we have to respond to is a trend increase in these levels.

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2.4.

HP/HT OPERATIONAL PROCEDURES

The foregoing text has highlighted the problems we might face on High Pressure wells. These factors are now taken into consideration when detecting and handling kicks. Basic kick indications and response are the same for all wells, ie:•

Flow Rate or Pit Volume Increase

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When the kick has been detected the well will be closed in in the same manner for all wells.

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Finally the methodology which must wells will be killed (typically the wait and weight method but increasingly the Driller's Method) is the same for all wells.

Kick Indicators High pressure wells exhibit additional characteristics which confuse kick detection. These are:•

Formation Charging

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Static vs Dynamic Downhole Temperatures

Formation Charging ( combination of ballooning and filtrate injection ) Given that with the effects of ECD, the formation is exposed to a greater hydrostatic head during circulation than when the well is static, formation charging must be expected.

Static well conditions

Effects of ECD pushing wellbore back

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How this manifests itself is in the wellbore giving back fluid once the pumps have been switched off. The speed at which mud is returned and the volumes vary from well to well and even within a given well as mud weight and well depth increases. This flow back is a product of the ballooning effect shown in the figure above and possibly the release of any filtrate which has been forced into the wellbore formations due to the extra hydrostatic head applied by the ECD. Most Mud Filter Cakes are not totally effective in preventing filtrate invasion into the wellbore formations. If there is any invasion then there will be local 'charging' of these formations up to the prevailing ECD pressure at that point in the wellbore. When the pumps are stopped, the local formation pressure will be be higher than the hydrostatic head of mud at that point so flow back from the formation into the well bore can occur. Can we predict exactly what these two phenomena will be in a well ? Probably Not ! Therefore to quantify these it is necessary to carry out extensive flow checks on the well until a pattern emerges. These flow checks could be 30 or 45 minutes but should be observed and recorded diligently. It is typical that the "flow back" rate from formation charging should decrease with time during a given flow check. Exactly how this manifests itself will only be evident when the flow check is carried out. At first, rig crews can find watching the well apparently flowing an alarming experience so it is advisable to discuss this effect in detail and illustrate by carrying out regular checks on what constitutes normal behaviour for the well.

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Static vs Dynamic Downhole Temperatures and the impact of this On HP/HT wells, downhole temperatures are typically in the range of 300 - 350°F. At the well design stage these are estimated and during drilling electric logs will confirm or deny the accuracy of these estimates. If the well is left uncirculated then it is a reasonable assumption that the mud in the borehole will assume the temperature of the surrounding formation. This phenomenon is important to consider when looking at the tools that can be run in HP/HT wells. Any tool with electronics, elastomers or oil in them will be sensitive to high temperatures. This means we need to consider our choice of electric logging tools, LWD/ MWD and even Jars. The most powerful Jars are typically Hydraulic jars. On some wells the hydraulic poil can boil and in these cases the more traditional mechanical jar ( eg the Dailey LI Jar ) is a better choice. The strike blow is less than a Hydraulic Jar in normal wells which is why they are not used so much but the hydraulic Jar may not be striking at all when used in very hot wells. It may seem ‘alien’ to be circulating for no apparent reason but on such wells sometimes its safer to keep circulating and cooling the well down rather than run the downhole components right up to their designed temperature ratings. From the Drilling Contractors perspective the same concerns apply to any Rig based Equipment which have elastomers in them. This means the BOP and surface manifolding needs to have elastomers capable of coping with the anticipated temperatures. Subsea BOP’s have a ready supply of cooling water around them and will reduce the temperatures being experienced by the BOP when compered to those on say a Land Rig or Jack up rig. A lot of Rigs now are putting temperature sensors on the BOP’s to eliminate some uncertainty. From the Well Production Testers perspective, again the higher temperatures need to be considered. When the well is flowing on a production test the produced fluid is all at ambient reservoir temperature. Downhole tools need to be designed to cope with the high temperatures and the surface equipment will see almost as high temperatures as the downhole equipment when in flowing mode. This is why there are very few HP/HT Test Spreads around the world and why when planning a well with the intent to Test it is important to ‘lock in’ a Spread which can be available at the time required. In practice this may mean committing to an HP/HT Test Spread for quite a while before it is actually needed ! The mud sitting in the tanks on the rig is probably in the range 80°F - 150°F depending on circulation pattern, water depth, tank capacity, ambient temperature etc.

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Consequently, as the mud system goes from static to dynamic, a cooling effect on the wellbore is unavoidable. This means that after extended circulation the wellbore will be substantially cooler than when the well has been left static for some time. Every time the pumps are stopped then the heat source from the surrounding rock will heat up the transition zone towards the wellbore and finally heat up the mud that is sitting in the wellbore. This is a natural phenomena and is to be expected. If the well were to be closed in after extended circulation then as the mud could not expand as it heated up it is reasonable to expect the shut-in pressure at surface to rise. This is in fact what happens in practice. As with Formation Charging it is phenomenon that rig crews are not necessarily familiar with, so again a demonstration of the effect is desirable. This can be done at the casing leak off test. If the cement/floats/pocket drill out takes a few hours then this circulation will have cooled the surrounding formations sufficiently for the phenomenon to be observed. Having drilled the pocket and circulated to an even mud weight, quickly pullback into the casing shoe, shut off the pumps and close the well in. The pressure build up gives a "finger print" for the well Press. Build Up following Kick Additional MudWeight Requirement Fingerprinting Press. Build Up

Time

This temperature effect acts in addition to the formation charging effect and the only readily discernible difference at surface is that the temperature effect will give a straight line relationship between closed in surface pressure and time for longer than might be expected for Formation Charging Effect. In some cases the straight line relationship can indicate potential required mud weights in excess of 20 ppg to regain "control" of the well. Common sense must prevail and it must be remembered that pore pressure will not exceed overburden pressure in a well otherwise the reservoir fluids would already have escaped.

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In practice we may not actually know how much of the effect is due to Charging and how much to Temperature. It really does not matter too much anyway, provided that we check the behaviour and have established what constitues normal behaviour. Despite understanding why we have these apparent well flows on HP/HT wells , it still goes against all we have been taught to pull out of the hole on a well which has apparently flowed 5 or 10 barrels once the pumps were switched off. Consequently, it is therefore expedient on trips to observe the flow check as mentioned above and then carry out a 5 or 10 stand wiper trip. The bit should then be put back on bottom and bottoms up circulated. Mud salinity, weight, temperature and gas levels should be observed during this circulation. If the well is flowing hydrocarbons, gas levels will rise. If the well is flowing formation water, salinity and mud weight will change.The only fluids we are going to find in these wells will be water, gas, condensate, oil or a mix of these.When our drilling fluid weighs 15.8 ppg and resembles toothpaste in texture then any of the above influxes are easily spotted by loss in mud return weight and huge differences in background gas levels and Hydrocarbon Chromatograhic breakdown. A lot of HP/HT wells have ended up ‘chasing their tails’ because higher gas levels are seen when circulating bottoms up after a wiper trip. The response has been to increase Mud Weight to control the gas . This would in a regular well ‘do the trick’ but on HP/HT wells the gas levels will stay the same or even go up Any time that the well has been static, the mud at the bottom of the well will heat up and when we circulate it to surface we will see higher gas levels. This on its own should not be your cue to raise the mud weight Mud Management on High Pressure Wells From the above text it can be seen just how many confusing effects could be taking place in the well. Despite anything you may be told to the contrary, in a Wildcat well these phenomena are not predictable with any degree of accuracy. Consequently, the only practical way to handle these phenomena in a safe manner is to:a)

Try to keep all mud properties and drilling parameters as constant as possible for as long as possible.

b)

Always circulate bottoms up following a short, check trip prior to pulling out of the hole completely.

Since we can only measure the mud at surface and guess what is happening downhole then the yardstick to apply is - "Did we have Primary Control ?". If the answer is

"Yes"

then the mud system has been effective in that role.

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Operational Procedures for Safe Handling of High Pressure Kicks Handling Kicks on High Pressured Wells The main mechanical weakness in the system in most cases is the Poor Boy Mud Gas Separator. Different Operators took different views on the safe throughput of a given Poor Boy. Early Poor Boys had 6” vent lines which clearly put more back pressure on the system when venting gas than say a 12” vent line would create. Some companies would produce graphs showing how much gas could be produced through the Poor Boy. These graphs are just based on theoretical modelling. As we know this is not always correct and since if the graph is not right then you will only find out when the liquid seal blows then a safer option is to just reduce the kill speed so that the gas throughput is decreased drastically to a level that is not even close to what could blow a seal. In practice when circulating out an influx the Choke manifold is warm or hot as mud passes through it. If there is gas breakout then the effect is like a refrigeration cycle. The choke manifold gets colder downstream of the chokes. At first this looks like condensation but even when working on the equator the choke manifold will then develop a coating of frost on it. Condensation can be expected and is not something to be concerned about however if when circulating frost develops on the BPM then its time to slow the circulation rate down until the gas cut mud has been circulated out. If gas is coming through the chokes then to maintain the kill the choke will need to be closed. In most normal kills once they get under way theres very little adjustment of the choke required ( because you are circulating a homogeneous fluid around – the mud that was in the annuus above a potential influx ) Another indication of gas coming through the chokes is a different noise coming from the choke manifold. At times there is slugging too. During kills attempts to shut down as much background noise as possible There is no excuse for not knowing what is going through the Choke manifold at any time Any well kill operations must be planned as multiple speed kills. This means checking slow circulation rates not only of 30 strokes per minute as is usual but also of 10, 15 and 20 strokes per minute. Sometimes the pumps can not run as slowly as 10spm but the minimum reliable running speed should be determined well ahead of time and not left to finding out ‘the hard way’ during an incident As a policy it is suggested that the well be killed at 30 SPM until frosting appears on the Manifold , the well starts slugging or theres a change in the sound coming from the manifold. Better Safe than Sorry ! A further precaution is to discuss the deficiencies of the Poor Boy with the Rig Crew and explain what happen if the equipment capabilities are exceeded. As mentioned earlier the temperature sensors on the BOP and choke equipment must be monitored during well killing operations. The manufacturers of the elastomeric products specify a continuous working temperature and a short term exposure temperature that the equipment is designed for. 12

Killing operations should be carried out within the B.O.P. working temperature envelope If temperatures begin to exceed the designed levels then the only recourse available is to slow down the kill operation or stop it completely until the BOP components cool . Glycol should be employed as the gas reaches the choke line. (Easily recognisable by a rise in Pchoke together with a change in tone and a chilling effect downstream of the choke itself. ) Given the known weaknesses in the kick handling system, measures should be put in place to spot failures in this equipment, should they occur we must ask ourselves "If there is going to be a failure, how will I detect it and how can I make it safe?" There are well documented Well Control Disasters which could have been contained had the Rig Crew been in a position to trace the immediate source of gas around the rig floor and implement a contingency plan. Practically speaking this implies:a) b)

Keeping a Subsea TV camera at the BOP during killing operations. Monitoring of the liquid seal blow off area at the Poor Boy Mud Gas Separator.

Having taken a kick and handled it safely the equipment must be prepared for the next one. To ensure that the equipment is ready two main checks are required:1. 2.

Check for erosion due to the high solids content of the mud. Flush the system with water to clear any residual barytes to prevent blockages.

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3.

WELL TO BE DRILLED

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Well Schematic (DRAFT)

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3.2 Well Specific Problem Prediction 1. Kicks The area we are drilling in is fairly well mapped with close outstep wells. Given the three known ( or predicted ) pressure ramps we will be controlled drilling as we approach these so are unlikely to go flying into over pressures. We will have Oil based mud in the hole for all of these ramps so can use the usual detection tools of gas levels, amounts of cavings etc to indicate pressures coming up. Naturally we have to be super careful when drilling ahead but probably the main source of any kick would be if (i) we swabbed in the well or (ii) didn’t appreciate the difference between static and dynamic bottom hole pressures (iii) Drilled into losses , causing a drop in hydrostatic head which reduced the primary control on a zone above this 2. Losses Losses could be expected in the well. These would most likely NOT be catastrophic but more probably just down to the ECD created when circulating a heavy mud around. 3. Hole Cleaning Not expected to be a problem in this well given that it is Vertical and the high mud weights will have high rheology. If the mud weight did not follow the pressure ramp properly there could be excessive caivings produced and these could create a hole cleaning / hole pack off problem 4. Differential Sticking Care needs to be taken once the reservoir section has been penetrated. We anticipate high pressures in the reservoir but there is always the chance that the modeling has given us a mud weight considerably heavier than we needed. Given oil based mud and drilling in a shale, it will be hard to detect this. Once the sands are penetrated then the differential sticking effect can be considerable. The usual precautionary practices should be used Keep string moving and if we need to shut down for whatever reason try and do so with no BHA across this section

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4. EXERCISES 4.1. We are drilling away in 12 ¼” hole at 3,500m at 10 m/hr with 11 ppg mud . Over the last few hours the torque on the string has been slowly but steadily increasing. The bit is a PDC and has 12 hours on it. What do you think is causing this slow increase in torque and how could you confirm your theory 4.2. Whilst drilling through the reservoir in 6” hole at 5300m. we need to make a connection. The flow back from the well seems a little heavier than the previous few stands so a decision is taken to close the well in and to circulate around using the Drillers method. This takes place without incident and after 1,100 bbls pumped ( 110% of hole volume ) we have seen no pressure spikes at the chokes, or cooling at the chokes. PDP and P choke pressures stayed constant all the time through the circulation. Is it safe to shut the circulation down, flow check the well and if OK go back to drilling ? 4.3. We are drilling at 5350m. and based on the LWD Gamma ray Tool we have penetrated around 300m of good sands since penetrating the reservoir at 5,050m. The Mud Logger has been reporting around 7% gas whilst drilling but this level drops back to 2% after bottoms up circulation. At 5351m the LWD crashes out. The LWD Engineers figure they can sort the problem in five minutes so the Driller picks up and slowly works the string . After ten minutes the LWD still isn’t working so the LWD Engineer figures that the problem must be more complex than he thought and reckons he could need an hour or so to try a few things out. What instructions should we now give the Driller 4.4. You are drilling ahead at 5400m when you get a call from the Rig Floor . The Driller says he thought the well was flowing on a connection so has flow checked, then shut the well in on the Annular BOP. There’s no real pressure to be seen on drill pipe or choke. He’s not sure how much flowed back on the connection because someone opened the drain on the trip tank just at the wrong time. He asks if its OK just to circulate around Drillers Method and see if theres any influx. You say that he should shut in on the rams before killing the well and he says that if he does that he can’t work the pipe therefore we could get differentially stuck in the sands. You are the Company Man. What are your Instructions to the Driller and why ?

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