There are numerous options to help reduce ECD’s on high angle wells. Although not applicable for all well types, the following sections provide possible solutions to reducing ECD in the planning stages of the well design.
1.2.1 Wellpath Design
The wellpath trajectory may impact ECD’s in several ways:
• The wellpath directly affects the total depth that must be drilled, and therefore impacts the annular pressures.
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Casing points may change with different wellpaths, allowing for increased margins at the shoe.• May be able to program lower mud weights with a lower tangent inclination.
1.1.1 Hole Size Optimization
In SEPCo’s deepwater GOM wells there is little scope to optimize the hole sizes (i.e. maximize clearances and minimize ECD) due to the number of casing strings that are required. However, in most hole sections, drilling oversize hole is required in order to accommodate larger casing strings. Drilling oversize hole will provide improved annular clearance in the openhole interval, but it does not address the long section of cased hole, which may dominate the ECD’s effect.
1.1.2 Casing Plan
Although there is limited scope to modify the casing plan for SEPCo’s deepwater GOM wells, in general, the casing plan should be analyzed for possible alternatives which may reduce ECD’s in critical sections. Although the ECD reductions from some of the design changes below may be small, it should be remembered that it is the combination of a number of small incremental reductions in ECD that generally make the difference (i.e. there are few “big hitters”).
1.1.2.1 Run Casing as a Liner
Running casing as a liner (instead of long string) should be considered if ECD’s are prohibitive for running (surge), circulating, and cementing that casing string, or for drilling the next hole section. For example, an intermediate casing could be run as a liner, and then tied-back (if necessary) after drilling the following hole section.
This approach adds complexity to the casing plan (e.g. liner hangers, tie-backs), and should not be considered lightly.
Additionally, hole cleaning in the large diameter upper hole section (above top of liner) should be considered carefully, since flowrates will probably be limited by the downhole tools. This may require the use of PBL or jet subs.
Also if high torque is a significant problem in the production hole, then the liner solution may be ideal. Under these circumstances, Non Rotating Drillpipe Protectors (NRDPP’s) or Roller Bearing Subs may be considered to reduce drilling torque.
Having the larger hole size above the liner top will allow the safe use of these torque reduction tools with a minimal impact on the ECD’s.
1.1.2.2 Use Alternative Casing Connections and Centralizers
The casing connections and/or centralizer type can have an influence on the downhole pressure while running or circulating casing. This is especially the case if any balling or cuttings accumulation occurs around these items. If ECD related problems are a concern while running or circulating casing, then alternate centralizers and/or connections should be considered.
The use of flush or near-flush connections will reduce ECD’s, especially if the annular clearance between the casing strings is small. For example, if 10¾” casing is run inside 13⅜ casing, the annular clearance around the couplings is improved by 125% by using a Hydril 521 connection rather than an LTC or BTC connection (Assuming 133/8” 68 ppf casing with 10¾” casing inside).
1.1.2.3 Use different sizes of casing
When ECD is critical, lighter weight casing strings should be used where possible. For example, 9⅝” 40 ppf casing could be used instead of 9⅝” 47 ppf casing. This would increase the cased hole diameter from 8.681” to 8.835” (it would also allow 8¾” hole to be drilled instead of 8½”, if the casing is special drift). Although this might not sound like much of an improvement, the annular area around a 7” tooljoint has increased by more than 10%. Given the dominance of tooljoints in ECD impact in 8½” hole size, this may be critical.
Simply using smaller casing sizes may have significant benefits. For example, rather than running 7” liner in 8½” hole, consider the use of 6⅝” liner (i.e. still allows 6” contingency hole size below). This will reduce the ECD while running and cementing the liner, often the highest ECD’s seen in the well.
1.1.2.4 Casing Flotation and ECD
Another ECD issue that is often overlooked on high angle wells is the ECD’s created while running casing. This can be an issue when running long strings with tight clearances or floated casing. The collapse pressure may be acceptable in a static situation, but the running ECD’s may be sufficiently large to collapse the casing or breakdown the formations (losses).
Dynamic surge pressures should always be factored into casing designs, particularly with flotation. When tight clearance are involved, open shoes and fluid diverter systems may be required.
1.1.3 Drilling Fluids
Drilling fluid selection and design is an important element for effective ECD management. Refer to SECTIO N 5 .0 for further details of mud selection and properties and their impact on ECD.
1.1.4 Drillstring Design
Refer to S ECT I O N 7.1 for further details of drillstring design. The drillstring design often plays a critical role in ECD management, especially on very shallow high angle wells where there is little formation integrity, and large OD drillpipe is required to overcome buckling problems. Regardless of the well type, the drillstring design should always be scrutinized and optimized if ECD’s are an issue.
For hole sizes larger than 8½" the choice of 5”, 5½” or 5⅞” drillpipe will have minimal direct effect on ECD pressures and annular velocities. It is in 8½" and smaller hole size that ECD effects quickly become a significant issue. The relatively small annular area is very sensitive to tooljoint and tubular diameters, especially when a cuttings bed is present to further reduce annular area.
If ECD’s are a problem in these smaller hole sizes, one effective approach is to use a tapered drillstring to reduce annular pressure drops. Certain projects may require three or more separate drillstring sizes (4” x 5” x 5½”) to manage ECD fluctuations, while maintaining the necessary torque, pickup and hydraulics capabilities.
Tooljoint selection is also critical to ECD’s. As already mentioned, in 8½” hole, the tooljoint clearance is quite small and will have a significant effect on annular pressures. Hole sizes larger than 8½” are not as sensitive to tooljoint size.
It is common to apply HWDP or larger OD drillpipe in shallow high angle wells to overcome buckling problems. Alternately, the drillpipe can be stiffened by the addition of Non Rotating Drill Pipe Protectors (NRDPP’s). If NRDPP’s or larger OD drillpipe is used, then the ECD effect should be allowed for. As a general rule-of-thumb, NRDPP’s add approximately 1 psi per protector. An
1.1.5 Bit and stabilizer design
The bit and stabilizer programs for high angle wells should be designed for maximum junk slot area (JSA). This is primarily to reduce the risk of tripping problems when pulling through cuttings beds. It will also reduce the risk of swabbing when pulling through cuttings beds. Additionally, an increased JSA will also reduce the pressure surge when running or reaming into the hole.
Although many engineers focus on the JSA of PDC bit designs, stabilizer designs are often overlooked (EXAMP LE 11.13 ). In particular, careful attention should be given to the stabilizers on steerable motors and MWD / FEWD equipment. These items often have much less JSA than the bit. If possible, avoid the use of sleeve stabilizers (common on MWD/ FEWD equipment) and replace them with integral blade or string stabilizers. This is often possible if planned in advance with the service company.
Clamp-on stabilizers should be avoided, if possible.
1.2 ECD M
ANAGEMENT- E
XECUTIONThe following sections discuss the main tools, parameters, and practices that will impact ECD management in the execution phase of the well.
1.2.1 Pressure While Drilling (PWD) Tools
Pressure While Drilling (PWD) technology is very valuable in applications where tight margins are involved. However the PWD tools have limitations which must be understood. The following issues should be considered:
• Hydraulics models should always be calibrated with actual PWD data.
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The PWD will only show the cuttings that are up in the flow regime or those suspended in the low angle sections of the well. The PWD will not see cuttings lying on the low side of the hole until the beds build up to a critical level. At this stage it is likely that the hole is close to packing off.•
The PWD will only show the pressure at the location of the tool. In certain applications (e.g. tapered drillstring, S-bend well), the ECD may actually be higher up the hole. Modeling should be used to analyze the ECD across the entire openhole interval.•
PWD data is not available in real-time with the pumps off. Therefore the tool is of no value when tripping out of the hole without circulation. Circulating just for the PWD data when tripping is not only time consuming, but is unlikely to identify developing problems quickly enough, and may create an additional risk of packing off.•
Real-Time models are now available that provide continuous ECD values, based on the actual wellbore conditions, even when the pumps are off. Although this is a valuable addition to the actual tool readings when circulating, it still does not allow tripping problems to be identified (i.e. output is from a model).•
PWD information is complex and difficult to interpret in real-time (affected by flowrate, rpm, rheology, temp, etc.).• Time-based logs should be reviewed at the end of each run to determine the effectiveness of practices and analyze problems.
1.1.1 Parameters
If tight margins are anticipated, or high ECD and / or losses are seen in an interval, the following should be considered with respect to drilling parameters:
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Prior to drilling out the shoe, it may prove beneficial to measure the magnitude of ECD variations with a range of flowrates and RPM’s (as per table below). This will provided some idea of the relative impact of each of theses variables.Note that the flowrate or rpm may dominate depending on various parameters. This exercise will also provide clean hole
0 40 80
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If excessive ECD’s induce losses, consider stopping and curing the losses before drilling on with reduced flowrate and / or rpm. The reduced parameters are only likely to make hole cleaning and therefore ECD’s worse.•
ROP may need to be controlled to limit the amount of cuttings being generated. Particularly if the flowrate and rpm have already been reduced (i.e. hole cleaning compromised) in order to lower the ECD, control drilling is advisable. The optimum ROP will most likely be determined by drilling off the PWD readings, maintaining the ECD below a targeted level.•
The mud system will need to be run as thin as possible (within barite sag limits) to minimize the annular pressure losses.•
Gel strengths should be as flat as possible to minimize pressure spikes when breaking circulation or moving pipe after stationary for a period of time.1.1.1 Practices
If tight margins are anticipated, or high ECD and / or losses are seen in an interval, the following should be considered with respect to drilling practices:
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Slide drilling results in the build-up of a cuttings dune immediately above the BHA. PWD tools have shown that ECD’s can increase sharply when pipe rotation is initiated after a long slide interval (EXAMP LE 11.5 and EXAM P L E 11.9 ) This is because of the instantaneous lifting of this cutting dune into the flow regime. There is also increased risk of packing off during this time. Slide intervals should be broken up with pipe rotation so as to re-distribute the cuttings more evenly up the hole.•
As with slide drilling, backreaming can cause a significant cuttings dune to form above the BHA. If backreaming too quickly (i.e. the pipe is moving faster than the dune), this can result in ECD spikes due to packing off. Down-reaming should be avoided where possible. This practice will place the highest loads on the wellbore. Refer to SECTI O N 0 .4.2 1 for detailed backreaming guidelines.•
Some mud systems tend to gel up when left static or if allowed to cool down. If this is the case, it may be necessary to‘stage’ into the hole when tripping back in. This requires breaking circulation at intermediate points when RIH, rather than when back on-bottom.
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It is a good practice in high angle wells to slowly increase the flowrate from a low level to the maximum, rather than simply breaking circulation at the planned drilling flowrate. This is true, as well, for rotary speeds. Whenever the pumps or the rotary are started up, they should be brought on slowly to ensure a minimum effect on ECD and cuttings loading.•
With very tight ECD margins, pipe rotation should be initiated first in order to start the fluid moving in the hole. This will help to break down the gel strength of the mud and minimize the surging effects as the pumps are brought on line.•
Sweeps should be avoided as they may pick up excessive cuttings in the lower angle potions of the well. If margins are tight, this may result in an increase in the annular pressure and ECD that is sufficient to breakdown the openhole formation.•
In deepwater applications, cuttings loading, and cold mud (thicker) in the riser needs to be considered. This may require the ROP to be controlled, or the riser to be boosted, to minimize the cuttings concentration and ECD impact.1.1.1 Operations Summary
The table below is a summary of ECD management guidelines for various operations. This may be used as a template and expanded on for specific applications.
OPERATION /
EQUIPMENT
ECD MANAGEMENT GUIDELINES
PWD • Ensure the tool is calibrated with correct TVD's used to calculate ECD
• Use PWD data to maximize drilling parameters while ensuring that the ECD does not exceed target values
• Time and depth-based logs need to be annotated with operations taking place
• Logs need to be provided to the appropriate people in a timely manner
• Use PWD data to calibrate ECD models and to project ahead
• Review time-based memory data after each run to determine the effectiveness of practices and analyze problems.
TRIPPING IN • Be aware of the max allowable pipe speed with pumps on and off. This should be defined at the well site based on PWD data
• Accelerate pipe slowly to avoid significant surge pressures
• Break circulation at regular intervals on the trip in.
BREAKING CIRCULATION • The pumps should be started at as slow a rate as possible and built up to the drilling flow rate – monitor PWD when data is available.
• If high ECD is a concern (confirm on PWD), consider starting drill pipe rotation (10-20rpm) before starting up the pumps.
REAMINGTO BOTTOM • This is the worst case for surging the formation – avoid where possible.
• Break circulation as above and ream down carefully to avoid surging. Where there are ECD concerns, ream using lower flow rates than while drilling.
• Reaming rate is to be determined at the well site based on ECD considerations.
BACKON-BOTTOM • Once on-bottom after a trip, break circulation as above
• Do not start drilling until the PWD indicates that the ECD has returned to background levels.
DRILLING AHEAD • Maximize ROP based on PWD and T&D readings.
• Minimize mud weight
• Maintain low values for PV and LGS
• Monitor PWD readings and adjust parameters accordingly
MAKING CONNECTIONS • Surge pressures are important at connections and while tripping. The ECD from circulating is combined with the surge effect. Pipe rotation will also increase ECD.
• Back-ream each stand once to remove cuttings from around the BHA.
• Minimize speed while washing back down to bottom.
TRIPPING OUT • Ensure that maximum allowable trip speeds are known in both the open and cased hole, with and without pumps on.
• Ensure the pipe is picked up slowly to limit the initial swab effect.
PUMPING SWEEPS • Should be avoided as sweeps can pick up large amount of cuttings that cause pressure spikes and may fracture the formations.
BACKREAMING • Keep a close watch on PWD and adjust parameters accordingly
• Break circulation and at the same time the string is picked up to avoid surge pressures
• Back-reaming should be avoided where possible RUNNING CASING /
LINER
• Running speeds should be based on PWD memory data recorded while drilling and tripping and the calibrated ECD model
• Lower mud rheology prior to POH with the last BHA
• Start and stage mud pumps up slowly
“Small changes in pump pressure can have a significant impact on the well bore.
Break circulation and move pipe SLOWLY”