Thursday, March 1, 2018

Drilling and Testing High Pressure High Temperature Wells

High-temperature, high pressure (HTHP) wells present special challenges to drill and test. Predominantly gas producers, HTHP wells may yield significant reservers in some areas. But the wells stretch conventional equipment beyond normal operational capacities. To safely meet these extreme conditions, traditional procedures have been modified and extra operational controls devised. 

 What constitutes HTHP is debatable. Perhaps the best definition has been coined by the UK departemen of energy:
"wells where the undisturbed bottomhole temperature at prospective reservoir depth or total depth is greater than 300 F (150 degree celcius) and either the maximum anticipated pore pressure of any porous formation to be drilled exceeds a hydrostatic gradient of 0.8 psi/ft or pressure control equipment with a rated working pressure in excess of 10,000 psi is required.

HTHP drilling is not new. In the late 1970s and early 1980s, many gas wells were drilled in the Tuscaloosa trend, Lousiana, USA, and other southern US states. These encountered temperatures above 350 degree F (177 C) and presures of more than 16,000 psi, not to mention highly corrosive environments. When HTHP interest switched to the North Sea in the mid 80s, new hazards were introduced. The wells were drilled offhsore, in exteremely hostile conditions and sometimes using floating semisubmersible rigs rather than fixed jackups.

Most of the North Sea HTHP wells are situated in the Central Graben - a series of downthron and upthrown blocks.  

The Central Graben contains several Jurassic gas condensate prospects at 12,000 to 20,000 ft [3660 to 6100 m] , with pressures of 18,000 psi or more and temperatures of up to 400 F [205 C].



 Water depth in the Central Graben varies between 250 to 350 ft [75 to 105 m] . Both jackups and semisubmersibles have successfully drilled wells in the sector, harsh environment jackups up to about 300 ft and semisubmersibles for deeper water. Jackups offer the advantage of contact with the seabed, eliminating heave and simplifying many drilling and testing operations. On the downside , in an emergency , jackups cannot be moved off location quickly. Also, few deepwater jackups are available.

This article looks at three key areas of HTHP operations in the UK Central Graben: drilling safety, casing and cementing, and testing. It also examines how North Sea experience has been used to help convert a jackup to drill demanding wells off Brunei. 

Drilling Safety

Preventing and controlling influxes of reservoir fluid into the well -called kicks- are always central to drilling safety, but in HTHP wells the dangers from a kick are amplified. The volume of a HTHP gas kick remains virtually unchanged as it rises in the annulus from 14,000 to 10,000 ft [4265 to 3050 m]. From 10,000 to 2000 ft [610 m] its volume triples. But from 2000 ft to the surface, there is a hundred-fold expansion.

Put simply, a gas influx of 10 barrels at 14,000 psi becomes 4000 barrels under atmospheric conditions. As reservoir fluid rapidly expands, it forces mud out of the well -unloading - reducing mud in the well, cutting hydrostatic pressure at the formation, allowing additional reservoir fluids to enter, and ultimately causing a blowout.

Wells drilled in the Central Graben have another complication - an unpredictable and sharp increase in pore pressure over a short vertical interval, sometimes less than 100 ft [30m]. And, while the pore pressure may rise rapidly, the fracture pressure does not. In some cases, convergence of pore and fracture pressures means that a small decrease in the mud weight of 0.5 pounds per gallon [lbm/gal] or less changes the well from losing circulation to taking a kick.

The difficulty of drilling in the Central Graben was highlighted in September 1988 when a blowout on the semisubmersible Ocean Odyssey resulted in fire and loss of life. Consequently, the UK Department of Energy esentially banned the drilling and testing of prospects with anticipated reservoir pressures exceeding 10,000 psi.



Because the consequences of failure in HTHP wells are so great, worst-case scenarios tend to be more conservative than for normal wells. Usually, the maximum anticipated size of a kick is set at the limit of detection -often 10 to 20 barrels. In HTHP wells, many contigency plans are based on the worst case of an influx completely filling the well at reservoir pressure.

When drilling with oil-base mud (OBM), there is a likelihood that gas entering the wellbore will dissolve into the mud's oil phase. This affects how the kick moves up the annulus and may mask detection. Since 1986, researchers at Schlumberger  have been studying the behavior of gas kicks, particularly in OBM. 

Planning requires realistic data: well temperature profile, nature of the anticipated reservoir fluids, expected maximum bottomhole pressure and pressure gradient, and rock strength and permeability. These are most often estimated using offset data -relatively plentiful in the North Sea. But where offset data are sketchy, predictive modeling may be employed. Shell has developed a model to predict rock strength and pore pressure in many areas of the North Sea. Shell has also modified a model designed to predict wellhead temperatures in offshore production wells to estimate surface equipment temperture when controlling a kick. 

Worst-case scenarios are used not only to specify equipment but also to draw up specific operational procedures, for example detailing what to do if the well takes a kick. Training is then used to comunicate these procedures to drilling personnel. Long before drilling starts, specific HTHP training courses may be run. Once on the rig, there are prespud meetings, crew safety meetings before starting key sections of the well, preshift meetings to discuss the current situation, and regular drills to practice important techniques like closing blowout preventers (BOP).

The three issues at the heart of HTHP drilling safety are kick prevention, kick detection and well control.

The best way of avoiding well-control problems is to anticipate situations known to precipitate kicks and take preventive action. Here are four examples:
  • When high-pressure formations are drilled, kicks commonly occur when the drilling assembly is being pulled out of hole. The movement of the assembly creates a piston effect reducing pressure below the bit, called swabbing. A time-consuming routine is usually adopted to check whether swabbing will cause an influx.
  • Before the assembly is pulled out of hole, the mud at the bit is circulated to surface - a procedure called circulating bottoms up. If this is free from gas, ten stands of drillpipe are pulled. The string is then run back to total depth (TD), and bottoms up are circulated. Gas in the mud is measured again, with an increase indicating swabbing. If swabbing does cause an influx, the mud weight may be raised slightly and the string pulled out of hole more slowly. Also, circulating mud while pulling out of hole helps stop swabbing -a process made easier by topdrive. 
  • The combination of relatively high-viscosity mud, deep wells and small annular clearences leads to higher than normal friction pressure during mud circulation. At the formation, mud hydrostatic pressure and friction pressure then combine to give the equivalent circulating density (ECD). This may be designed to balance formation fluid pressure. But during a connection, mud flow stops and friction pressure is zero. Witch reduced ECD, small quantities of gas, called connection gas, may permeate from the formation. 
  • Kicks don't occur just during drilling coring also causes problems. The relatively small clearence between core barrel and open hole increases the possiblilty of swabbing when pulling out of hole. This may be combated by limiting the amount of core cut any one time - usually to 30 ft or less - and pulling out of hole very slowly, checking for flow and monitoring gas in the mud.
  • Tight margins between pore pressure and rock strength ,as in the Central Graben, make lost circulation common, complicating well control. The normal practice on encountering losses is to pump lost circulation material (LCM) in the mud. If LCM fails to block the formation, the strategy is to pull out of hole, run back in with open-ended pipe and spot cement across the loss zone. Some slurry is squeezed into the formation and, once set, the remainder drilled out. However, in HTHP wells, the swabbing effect of pulling the bottomhole assembly out of hole prior to spotting the plug may induce a kick elsewhere in the wellbore. In this case, the only solution is to spot the cement plug through the bit. To make this easier, rotary drilling is favored, rather than using a downhole motor that may clog up with cement.

 Kick Detection: Because no technique can guarantee kick-free drilling, influx detection remains vitally important. Traditional influx detection relies on observing mud level increases in the mud pits, or performing flow checks - stopping drilling to see if the well is flowing. Comparisons of mud flow rates into and out of the well are also used. To make detection more reliable, transfer of mud into the active system is tightly controlled and usually not allowed while drilling.

Recently, Anadrill has introduced the KickAlert early gas detection service based on the principle that acoustic pulses created by the normal action of the mud pumps travel more slowly through mud containing gas they do through pure mud. The pulses are measured as pressure variations at the standpipe as the mud enters the well and at the annulus as it comes out. If the well is stable and no gas is entering, the phase relationship between the pressure pulses in the standpipe and annulus is constant, or changes gradually as the well is drilled deeper. When gas enters, the pulses travel much more rapidly up the annulus, dramatically changing the phase and setting off an alarm on the drillfloor. 

 The presence of high-pressure gas may also be indicated by changes in drilling conditions. Increases in rate of penetration, torque or mud temperature in the mud return flowline on surface may all signify the onset of a kick. Computerized monitors help drilling personnel keep track of trends and spot abnormal situations using quick-look interpretations on a drillfloor screen.

Well Control: As soon as a kick is detected, drilling is stopped and the well is shut in. The influx must then be circulated out while keeping the presssure under control. 
The BOPs are the primary means of well closure. Once a kick is suspected, the annular blowout preventer is first closed. A flexible rubber element is inflated using hydraulic pressure, and is sufficiently flexible to seal around any downhole equipment. When it has been established that no tool joints are in the way, the pipe rams are then shut, sealing around the drillpipe. Now mud can no longer return through the flowline to the shale shakers and mud pits. Instead it must travel through the chokeline to the choke manifold, which is used to relieve mud pressure at surface.

The capacity of a BOP to resist pressure depends on the elastometric seals inside the rams and their likelihood of not being extruded. As temperature increases, extrusion becomes more likely. Seals may have to withstand prolonged temperatures that top 400 degree F - beyond the limit of ordinary components. Finite-element analysis has been used to identify which areas of the BOPs are most affected by heat and which seals need special elastomers rated to 350 degree F. 

Once the BOPs and choke are closed, pressure builds in the annulus and drillpipe. The maximum drillpipe pressure is used to calculate bottomhole pressure, which is used to plan the kill strategy. Well-kill strategy also takes into consideration the drilling operation underway during the kick.

If the kick occurs during drilling, weighted mud - either from a premixed or specially prepared supply - may immediately be pumped down the drillpipe. The formation fluid influx is gradually displaced up the annulus, expanding as hydrostatic pressure decreases. At surface, the mud-influx mixture travels to the choke manifold via the chokeline and has its pressure reduced by the choke. The well is slowly brought under control by carefully selecting mud weight and choke opening.

Casing and cementing 

In Central Grabben wells, choosing the location of the intermediate -usually 9 5/8 in. -casing shoe is crucial. Ideally, casing must be set above the high pressure reservoir and just below a zone of weak Hod chalk.





If it is set too high, the weak formation will be exposed to subsequent high pressure, and the only solution is to set a short, perhaps less than 100 ft, 7-in. drilling liner. This has the undesirable effect of reducing the diameter of further drilling.

Consequently, the  shoe is usually set at the bottom of the Hod chalk, in the Lower Cretaceous clays or in the Kimmeridge clay just above the reservoir. But finding the casing point is not easy - vertical seismic profile surveys may be employed. As drilling approaches the likely casing point, it is intermittenly halted, bottoms up circulated and cuttings examined by a geologist or micropaleogeologist.

Pressure is a key consideration when designing the casing string. The 9 5/8-in casing is often designed to withstand complete evacuation to atmospheric presssure with reservoir pressure in the annulus between open hole and casing. Given the high pressures, heavy-weight casing is usually required throughout the string.





Once the casing string has been run, the shoe must be cemented to resist the high reservoir pressure that will be encountered almost as soon as the next section of drilling starts. Location of the top of cement (TOC) of the 9 5/8 in. casing is sometimes an issue. I normal wells the TOC is usually above the previous casing shoe, with fluid trapped in the annulus above the TOC. When the HTHP wells are drilled, hot mud passing up the drillpipe-casing annulus heats fluid in the casing-casing annulus, causing it to expand.
For a subsea-HTHP well, the presure has no escape and it can burst or collapse the casing. For this reason, the TOC for 9 5/8 in. casing in a HTHP well is sometimes kept below the 13 3/8 in. shoe to allow annular pressure to dissipate into the formation.

In most HTHP wells a 7-in. liner is run, although in some cases it may be possible to cement a 7-in. casing to surface. In either case, the cement job must isolate the high-pressure zones to facilitate well testing. This requires good cementing practices and a carefully designed slurry.

Mud removal is vital in achieving strong cement bonding to the formation and casing, and sealing against high pressure. Even small quantities of contaminant in the cement slurry compromise the final setting strength. Spacers reduce contamination, but high temperatures may thin or destroy spacer polymers causing weighting agents to settle.

The tight pressure constraints found in HTHP wells mean that the traditional density hierarchy -  cement heavier than the mud with an intermediate spacer -is difficult to achieve without exceeding formation fracture pressure. A viscosity hierarchy is also desirable, but when cement is thicker than mud , the friction pressure may increase beyond the limit. This emphasizes the importance of other good drilling and cementing practices: drilling an even wellbore, circulating and conditioning the mud correctly, and centralizing the casing.



In gas zones with a low overbalance, there is the risk that high-pressure gas will enter the cement during hydration and create large channels. Elsewhere, loss of fluid into the formation reduces the slurry liquid-to-solid ratio, changing rheology, density and setting time.

Once the 7-in. liner is cemented, casing pressure tests simulate losing control during well testing and exposing the entire string to formation pressure. Test are generally carried out using a retrievable packer set above the theoretical top of cement in the annulus. 

Testing :

Cores are taken and logs run where possible and used to decide whether and where to test. Coring may be limited by its prospensity to swab the well and cause kicks. For logging, the tolerance of all standard wireline logging tools to high temperature may be boosted by thermal insulation.

Once  cores and logs have indicated the presence of hydrocarbons, a well test is needed to determine parameters like reservoir extent and permeability, and to sample reservoir fluid. In almost all cases, a cased-hole drillstem test is used. The well is normally shut in using a downhole valve and flow is controlled at surface using a choke manifold. Periods of flow and shut-in allow collection of data like flow rate and pressure changes. 

The rates and pressures experienced during testing HTHP wells are prodigious. One test by Ranger Oil Ltd. in the Centrl Graben using a jackup rig resulted in 44 MMscf/D of gas and 4400 B/D of condensate. The maximum recorded tubing-head pressure was 12,500 psi, the bottomhole temperature was 386 degree F (197 degree C.

Downhole Equipment:

Sealing off the candidate formation requires a packer. During an HTHP test, differential pressures across the packer may exceed 10,000 psi. For this reason, permanent packers are usually chosen, rather than  retrievable packers used in lower pressure test. With wireline (or very ocassionally drillipipe), the packer is installed complete with a sealbore, and a seal assembly is then run with the test string to seal into the packer.

Perforating with wireline guns is generally avoided during HTHP tests, so tubing-conveyed perforating (TCP) is preferred. Unlike wireline perforating, TCP allows the reservoir to be perforated underbalanced and immediately flowed through the test string.Because the guns will spend hours in the well prior to firing, high-temperature explosive is used. In most cases, the TCP guns are run as part of the test string, rather than hung off below the packer. This reduces the time that the explosives spend downhole and allows the guns to be retrieved in case of total failure. 



In most cases, test tools are operated using annular pressure. The condition of the fluid in the annulus, usually drilling mud, plays a critical factor. High-density, high-solids drilling fluid may plug pressure ports and reduce tool reliability. Solids may also settle, potentially sticking the test string. The effects on heavy, water-base mud of being static in a hot well have been thoroughly investigated in the laboratory and the performance of test tools has been improved to reduce downhole failures. In some cases, the annular fluid is changed to high-density brine, which is solids free but increases the expense of the test.


















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