Drilling mud is used to control subsurface pressures, lubricate the drill bit, stabilize the well bore, and carry the cuttings to the surface, among other functions. Mud is pumped from the surface through the hollow drill string, exits through nozzles in the drill bit, and returns to the surface through the annular space between the drill string and the walls of the hole.
As the drill bit grinds rocks into drill cuttings, these cuttings become entrained in the mud flow and are carried to the surface. In order to return the mud to the recirculating mud system and to make the solids easier to handle, the solids must be separated from the mud. The first step in separating the cuttings from the mud involves circulating the mixture of mud and cuttings over vibrating screens called shale shakers.
The liquid mud passes through the screens and is recirculated back to the mud tanks from which mud is withdrawn for pumping downhole. The drill cuttings remain on top of the shale shaker screens; the vibratory action of the shakers moves the cuttings down the screen and off the end of the shakers to a point where they can be collected and stored in a tank or pit for further treatment or management.
Often two series of shale shakers are used. The first series (primary shakers) use coarse screens to remove only the larger cuttings. The second series (secondary shakers) use fine mesh screens to remove much smaller particles. In general, the separated drill cuttings are coated with a large quantity of drilling mud roughly equal in volume to the cuttings
Additional mechanical processing is often used in the mud pit system to further remove as many fine solids as possible because these particles tend to interfere with drilling performance. This mechanical equipment usually belongs to one of three types: 1) hydrocyclone-type desilters and desanders, 2) mud cleaners (hydrocyclone discharging on a fine screened shaker), and 3) rotary bowl decanting centrifuges. The separated fine solids are combined with the larger drill cuttings removed by the shale shakers.
If the solids collected by the shale shakers are still coated with so much mud that they are unsuitable for the next reuse or disposal step or if the used mud is valuable enough to collect as much of it as possible, the solids can be further treated with drying shakers utilizing high gravitational separation, vertical or horizontal rotary cuttings dryers, screw-type squeeze presses, or centrifuges. The cuttings dryers recover additional mud and produce dry, powdery cuttings
Polycrystalline diamond bits (PDC) use thin diamond layers bonded to tungsten carbide-cobalt studs or blades. The extreme resistance of diamond to abrasive wear makes it possible to use the shearing action of the cutters for drilling.
PDC bits are more efficient than the crushing action of roller-core bits. A typical bit in shallow heavy oil areas can be used about 3 times. PDC bits produce larger amounts of cuttings due to the speed of penetration and thus flush volumes should be adjusted to keep the bit clean and cooled.
Slant Drilling
Slant drilling is well suited to shallow gas and heavy oil since conventional directional drilling could not provide sufficient lateral displacement to penetrate the targets. Even with a continuous build rate of 3° per 30 m from surface, the maximum lateral displacement achievable was 300 m with a terminal angle of 60 ° being realized. Using slant techniques, a 300 m displacement is achievable with the maximum allowable spud angle of 45° found on slant rigs.
It is critical that azimuth and inclination is set to take full advantage of the target geometry. In order not to lose lead angles, the well should be spudded with a full gauge near the bit stabilizer. Slant rigs are spudded with left hand isolation until the rearbit stabilizer is buried. This prevents the tendency of the bit to walk at spud.
Photo: Husky well at Lloydminster
Interwell spacing of at least 5 m is necessary so that the service rig can be oriented for any workovers. The wellbore profiles will be smoother and thus rod and tubing wear should be less.
Photo: Slant well work at PetroCanada Fort Mackay
Slant drilling rig technology moved forward in the early 1990s when Precision Drilling Corp., in conjunction with PanCanadian Petroleum Ltd., designed and implemented a
new slant drilling rig. This new design represented an important milestone in heavy oil drilling. Its longer-than-standard drill pipe - 45 ft (13 m) vs. 30 ft (9m) - offered significant benefits of flexibility and operational capabilities, which led to the term, "Super Single."* (Precision Drilling)
Background
In the 1980s a new alternative appeared in horizontal drilling. The well would start vertical, then be deviated to horizontal with downhole mud motors, measurement-while-drilling (MWD) and bent-sub technology. The process increased production, but the mud motors, and sophisticated directional drilling techniques and equipment were expensive.
The 1990s saw the revival of slant technology, which was used most successfully in heavy-oil drilling at shallow depths. This differed from directional drilling in several ways:
• It followed a shorter, more direct route. Wells could be spudded at an angle - usually 30° to 45°- and then aimed straight at the target, Fig. 1.
• It was less expensive, faster and more productive than directional horizontal drilling.
• Slant drilling allowed shallow heavy-oil deposits to be developed from one or several pad locations, which vary in number of wells. Pad drilling also emerged as a way to minimize environmental impact because it allows multiple-well access to larger areas and targets beneath sensitive areas, such as lakes and towns.
The technique started by drilling from a slant angle at the surface (45° max. in 1.5° increments), and zeroed in on shallow-depth targets with a 150-ft (50-m) radius. The technique did not require downhole motors or MWD technology. Improvements to the technology, combined with customer cooperation reduced time and well costs up to 50% on heavy-oil pad projects.
The Evolution Of Super Single Rigs
Customer feedback and operational experience provided insight into a far-reaching set of issues including pad location and size, safety, drilling efficiencies, design innovations and other enhancements to leverage the benefits of the rig design. By 1993, the rig had a depth rating of 6,600 ft (2,200 m). With each generation, additional quantitative and anecdotal data enabled further improvement of the performance, capabilities and operational efficiencies. Today, with the fifth and sixth generations now deployed, the rig makes up 8.1% of the company's 246-rig fleet.
The success of the rig can be attributed to technology that controls critical functions, makes the work environment safer for rig crews and improves equipment control. Combined with pad drilling, the slant concept offers fast and simple movement from site to site and the ability to perform more than just a single type of well drilling.
Remote-Control Features
Fully mechanized, using state-of-the-art technologies to minimize manual labor, the rig's remote-control features reduce the crew's exposure to harsh weather. These features include:
• Hydraulic power wrenches for make-up and break-out of tubulars • Hydraulic power wrench carrier
• Hydraulic top drive
• Hydraulic BOP handler and hydraulic pulldown • Pneumatic tubular slips
• Hydraulic pipe tables for gravity indexing of tubulars and casings to and from the catwalk
• Hydraulic tubular kickers and indexer systems that index tubulars from the catwalk individually into the tubular handling boom, or kick tubulars out of the handling boom and onto storage racks or tables.
In addition to efficiency gains, this high level of equipment control has the specific benefit of drastically reducing connection times. The hydraulic pipe tables lift joints of drill pipe to the catwalk, where the hydraulic pipe arm is located. The indexers then roll the joints onto the catwalk and into the pipe arm, which lifts the joints individually to the derrick. A top drive screws directly into each joint, eliminating the need for an awkward and heavy kelly. The entire connection process takes less than a minute, a fraction of the usual three to five minutes required by conventional single and double rigs, Fig. 2.
Maintenance costs are the same as those for single, telescopic double and jackknife double rigs. The reliability of the system is reflected in mechanical downtime of less than half a percent.
Personnel requirements on the rig remain the same. Someone still needs to operate the controls, run the equipment, perform basic maintenance, disassemble the rig and rig up at the next drill site. The chief difference is that the equipment does most of the work,
eliminating the labor-intensive and dangerous component of tubular handling. This not only makes the entire process more efficient, but also improves safety considerably. Safety
Most injuries to drilling crews occur while they are handling tubulars, with most of those injuries occurring on the rig floor and catwalk. The rig's control processes help to alleviate this problem. The remote-controlled hydraulic tubular handling boom enables the
derrickmen to safely remove and add tubulars and accessories to the drillstring
mechanically rather than manually. The boom also provides for the handling of casing. Drilling crews no longer must move tubulars from racks to the catwalk or position them on the rig floor. Beyond that, hydraulic safety lockouts for mast position pinning and crown maintenance reduce the need for personnel to climb the mast, Fig. 3.
Drilling Efficiency and Versatility
The rig, which has reached drilling rates as high as 607 ft/hr (185 m/hr), can drill vertical, deviated wells, and underbalanced wells to 9,000 ft (3,000 m). The sixth-generation rig design uses programmable logic controls to monitor the position of traveling blocks and employ a fail-safe disc brake to control the block speed as it approaches the crown. The system also slows the block as it nears the rig floor. This level of PLC control enhances process efficiency and helps prevent potential damage to the rig floor and the crown. A tri-parameter auto-drilling system enables the controls to make adjustments on its own if
drilling should deviate from safe operating parameters, thus reducing the potential for human error.
The rig can be moved quickly. For example, a typical double rig racks drill pipe and collars in the derrick in 62-ft stands. Before it can be moved to another well, the stands must be run back in the hole and broken into single joints before laying the pipe down. However, the slant rig's tubular handling system lays down each joint during every trip out. The tubulars can be moved at any time without breaking down stands.
The rig design is also simple and compact, requiring only eight loads for well-to-well movements on a pad (including boilers and tubulars). In some cases, movements on a pad can be completed within two hours. The rig can also be moved one to two miles in four hours and is easily disassembled for highway transportation.
Since 1990, 19 rigs have drilled more than 5,000 wells, and the global market is expected to grow as the rigs' benefits become known. They are now used in Canada, Mexico, Venezuela and Kazakhstan.
Feedback From The Field
Over the past five years, Lane Dunham, drilling manager with EOG Resources Canada, Inc., has used the rig for well depths of 1,500 ft to 7,500 ft (500 m to 2,300 m), because of greater flexibility and savings in rig time and operating costs due to the rig design's efficiencies and ruggedness. He experienced penetration rates of 500 ft/hr (150 m/hr), almost doubling the drilling efficiencies.
Dunham also observed quicker connection times, reporting, "The drill pipe is 45 ft (13 m) long - that's 50% more than conventional single rigs, which use the standard 30-ft (9-m) drill pipe. This means you don't have to stop drilling as often to add joints to the drillstring. Connection times typically take one minute with the rig, and that can add up to time saved on the program." Dunham adds that because there are fewer connections, there is less wear and tear on the mud motor and drillbit components, and therefore, most wells can be drilled with one bit.
Perhaps one of the biggest time savers, reports Dunham, is the rig's design of the remote-controlled tubular handling equipment and the top drive. Rather than manually racking the drill pipe on the rig floor before logging, a hydraulic arm operated remotely by the rig crew lays the drill pipe on the pipe racks.
"Once we are done logging, we can run the casing immediately because the pipe has already been laid down," he explained.
For Dunham, the savings have been up to 12 hr for a typical 6,500-ft (2,000-m) well. These time-savings can be a significant advantage for oil companies with multiple well sites such as Petro-Canada's 50-well drilling program in northern Alberta. The intensive and
demanding program, led by Drilling Superintendent Dough Fletcher, employs SAG-D (steam-assisted gravity drainage) recovery method for extracting oil. In this technique, one
horizontal well is drilled on top of another horizontal well. Steam is pumped down the top well to heat up the tar sand so the oil flows from the top well to bottom well.
Since employing the rig in January of 2001, Petro-Canada has been able to reduce mechanical downtime to nearly zero, achieving an overall budget time savings of nearly 30%, and has eliminated lost time accidents completely.
In addition to the same 50% reduction in connection time as Dunham, Fletcher has also found it easier to orient downhole motors and back-ream with the rig.
Petro-Canada has been able to move the rig and spud the next well in less than two hours from the time it's released from the previous well. With four pads and 50 wells, the rig's mobility was a significant factor in improving the efficiency of Petro-Canada's drilling program.
Part of the rig's efficiency also has to do with the top-drive design, as Fletcher explains, "The rig is much faster because you're operating at a higher range of rpms and you can have much quicker connection times."
He adds that the top-drive capabilities also reduce the risk of experiencing stuck pipe. Petro-Canada has drilled more than 105,000 ft (32,000 m) in the last eight months and experienced zero stuck pipe incidents. That's drilling mainly in tar sand, sand and gravel, but also clay, shale and silt.
One of Petro-Canada's most notable accomplishments has been its safety performance. The program has had zero lost-time accidents among its crew since employing the rig. With 50 to 60 people a day on the rig, drilling at a steady pace, an accident-free record is
remarkable. Fletcher says he owes this in large part to the remote-controlled tubular handling features of the rig.
This is true regardless of geographic location. In Venezuela, Pearl Turner, operations manager with PetroZuata, drills in the Zuata field - a heavy-oil sand / shale formation. His drilling program included 240 multi-lateral horizontal wells, which used the rig (PD735). Turner says that with the rig's air slips and iron roughneck and pipe handling arm, trips can be made without a crewmember other than the driver and derrickman. The driller and derrickman controlling the hydraulics can trip in and out of the hole.
PetroZuata also experienced faster rig moves compared to conventional drilling rigs. Normally, conventional rigs take at least 30 hours to move from pad to pad. The rig (PD 735) used by PetroZuata took only 15 hours to move to another pad. Due to its size and compact design, the rig can be prepared to move in two hours and rigged up in the same amount of time.
Continuous back-reaming was also listed as an advantage of the rig because each joint is handled by making up the top drive into the pipe. He adds that the rig can pick up casing joints as regular joints and run casing without needing a power tong. The necessary torque for the casing can be applied by the rig's top drive system.
In PetroZuata's case, PD 735 Super Single rig broke a world record in drilling time, achieving 5,193 ft in one day. The rig routinely drills 8,000-ft measured-depth horizontal wells at a true vertical depth of 2,100 ft without any issues. Overall, the rig had no
significant limitations with the exception of its drawworks and pulling capacity. The small size may pose problems for some of the larger projects.
Although Petro-Canada is using the rig only on horizontal SAG-D wells at a 45° slant for this particular program, the rig also works well on vertical wells. According to Fletcher, the company's SAG-D program in northern Alberta is expected to be completed four months ahead of budgeted schedule.
Underbalanced Drilling
In conventional drilling, the drilling fluid a) brings the rock cuttings to surface b) stabilizes the borehole
c) cools the bit
d) controls the formation fluids
The well is at balance if the borehole and formation fluid pressures are equal: there is no net fluid flow out or into the borehole. Usually, the drilling fluid properties are chosen in the overbalanced situation to prevent formation fluids from entering the wellbore during drilling. Materials are added to the drilling fluid to restrict this flow by depositing a low permeability filter cake on and adjacent to the borehole wall.
In underbalanced drilling, the drilling fluid pressure in the borehole is less than the formation pore fluid pressure, and thus, when the formation is drilled, fluids flow into the wellbore. What are the advantages to underbalanced drilling?
A. Increased penetration rate and bit life. Air drilling rates have been reported
to be 10 times faster than for conventional mud drilling. The confinement imposed on the rock by the overbalance is also removed, decreasing the apparent strength of the rock and thus reducing the work needed to drill through the formation.
B. Reducing drillstring sticking. If the drillstring becomes embedded in the filter cake, the drillstring is differentially stuck. Other mechanisms can cause sticking, but if there is no filter cake and no pressure acting to clamp the drillstring when the well is underbalanced.
C. Minimizing lost circulation. It is possible for the drilling fluid to be lost by
flowing into a very permeable formation or fractures and not returning to the surface. Lost circulation materials usually have to be added to the mud to plug off this path. In underbalanced drilling, there is no force driving the fluid into the formation.
D. Earlier formation evaluation and production. Hydrocarbons will be carried with the drill cuttings and thus potentially productive zones can be determined earlier. With suitable surface equipment, oil can be collected while drilling.
E. Reduced stimulation required. Formation damage can occur when solids or
liquids enter the formation while drilling overbalanced. When the well is drilled underbalanced, formation fluids enter the wellbore from the permeable formation. Less stimulation will be required to reduce the formation damage. The interpretation of the openhole logs will be easier since there is no saturation change next to the wellbore which can mask the presence of hydrocarbons.
Risks of Underbalanced Drilling
A. Wellbore instability. Because the wellbore pressure is lower than the formation pressure, the wellbore support is no longer there.
B. Water inflows. Formation water can moisten the drill cuttings downhole,
adding water, the drilling cuttings can be prevented from attaching to each other. Often, when water influx first occurs, dry gas drilling is switched to mist drilling.
C. Downhole fires. These can be avoided by using non-flammable circulating
fluids such as air foams or nitrogen.
D. Horizontal and directional tool problems. When drilling these types of
wells, the MWD tool cannot operate with the fluids used for underbalanced drilling since the pressure pulses through these fluids have low amplitude. Electromagnetic systems have to be used.
Current Types of Underbalanced Drilling Fluids
Four basic types of fluids are used for underbalanced drilling: a) Air / Nitrogen
b) Mist / Fog c) Foam
Air is the simplest drilling fluid to use. The inert gas, nitrogen is also used. It is generated with membranes that remove oxygen from the air flow delivered by compressors before it is pumped downhole. Natural gas can be cheaper than nitrogen, particularly if drilling close to natural gas pipeline but fire protection guidelines must be followed. Air flow rates (min 3000’/min) must be high enough for adequate hole cleaning.
Underbalanced Drilling in Estreito Heavy Oil Pool Brazil
Estreito field is in Brazil's northeastern region and has its production zones depleted, Fig. 1. Discovered in 1982, it has more than 700 wells. Estreito field's producing reservoir is very shallow, and the formation is very unconsolidated. This poses a special challenge to maintaining an underbalanced condition during drilling. Special care is required, not only during planning and execution of well operations. Four horizontal wells were planned and drilled underbalanced. In these wells, a compact, vertical gas-liquid separator was
successfully tested with an automated control system and data acquisition system developed by Petrobrás. A skimmer was used for drilling solids, fluid-oil separation.
OVERVIEW
Estreito field produces heavy oil with high viscosity (>1,000 Cp). Average output from vertical wells is between 3 and 4 m 3 /day (19 and 25 bopd). Horizontal wells produce 10 to
15 m 3 /day (63 to 94 bopd).
The wells' low productivity increases lifting costs, requiring such special recovery methods as cyclic and continuous steam injection to increase output. Use of the UBD technique at Estreito tested this method's technical and economical feasibility to increase oil production. This four-well campaign offered the opportunity to field-test several new pieces of
equipment and operational procedures that would be used offshore later, where wells with aerated fluid would be drilled for the first time from a drilling vessel.
The objective of the four wells described here was to drain an area under the Açu River. The horizontal section extension was approximately 150 m (492 ft), drilled with an
8-1/2-in. bit. Original pressure of this unconsolidated sandstone reservoir was 20 kg/cm 2 . The
estimated depletion is about 3 kg/cm 2 in the area under the river - still not heavily depleted.
Formation fluid is basically oil with no associated gas.
A 13-3/8-in. conductor was set at 40 m (131 ft), and the intermediate 9-5/8-in. casing was set at 90° inside the reservoir. Finally, the 7-in., slotted production casing was set in the horizontal section, Fig. 2. This casing was cemented using a stage tool inside the 9-5/8-in. casing. An external casing packer was used to avoid over-pressuring the formation during cementing.
DRILLING TECHNIQUE
The 8-1/2-in. horizontal section was drilled underbalanced using a two-phase fluid comprised of water and xantham gum to keep it slightly viscosified. This fluid sustained the iron sponge used to avoid any H2S problems (which did not occur). Anti-corrosion
measures were also applied, and pH was kept above 10.5. The gas was nitrogen pumped from trucks.
Liquid and gas rates were planned to assure an equivalent circulating density lower than the reservoir pressure, estimated at 7.4 ppg. Because the reservoir is unconsolidated, wellbore stability studies were conducted to determine the collapse pressure. Best estimation was that this collapse pressure would be equivalent to 6.5 ppg, even though several
uncertainties can affect the value's accuracy.
Two static and one transient simulator were used to simulate well hydraulics, and liquid and gas rates. The flowrates found in the simulators were around 240 gpm of liquid (with an 8.5-ppg, liquid-phase density) and 350,000 cfgd. In the field, liquid rates of 150 to 200 gpm and gas rates of 500,000 to 700,000 cfd were used. The difference between predicted and actual flowrates was due to pressure losses at the surface, greater than originally estimated. Liquid phase density was also higher than the one used in the simulations.
The transient simulator was used to estimate the effect of pipe connections (adding new pipe joints to the drillstring as drilling went deeper) on BHP. This simulation showed that it was going to be very difficult to keep BHP between the limits defined by the collapse pressure (219 psi) and the reservoir pressure (250 psi). What happened was that when reinitiating circulation, a liquid slug formed during connection of new pipe that would provoke an increase in BHP. Conversely, when circulation was stopped, BHP would gradually drop, due to the absence of friction loss. This would cause BHP to go below collapse pressure, which consequently, would cause wellbore instability.
Theoretically, the solution for this problem was to use a nitrogen pre-charge before connecting new pipe. In this case, liquid injection would be interrupted 90 sec before the gas, and the emergency shutdown valve on the flowline would be closed during
connection, keeping the well pressurized. The goal of the pre-charge is to add more gas to the liquid that will remain at the bottom of the well due to gas segregation. By closing the valve, this segregation will be minimized, keeping BHP above collapse pressure.
Connection time is also important - for simulation purposes, it was estimated at 4 min. An electromagnetic MWD was used to control the well's direction. A gamma ray tool and an annular BHP sensor were connected to the MWD. Both data sets were recorded in real time at a distance of 14 m (46 ft) from the bit. These data were recorded every 96 sec. SEPARATION/PROCESS SYSTEM
While liquid nitrogen was pumped from trucks, gasified and then injected through the standpipe, the liquid phase was pumped by mud pumps. The mixture of both phases occurred in a Y connection at ground level before going up to the standpipe.
On the return, a rotating control head (Williams 9000 model) was used above the regular BOP stack, allowing return flow to go to the separation system. This rotating head allowed a maximum 1,000-psi static pressure and 500 psi when rotating the string at a maximum 100 rpm.
After the rotating head, the flow passed through a choke manifold specifically designed and built for underbalanced operation. Before the choke, there was a normally closed safety valve with a remote pneumatic actuator. For this operation, the system was changed to normally open. The 3,000-psi working pressure choke had three streams - one full, and two with a variable choke pneumatically controlled. A sample catcher was located after the choke that was also specially designed and built, with screens inside cylindrical reservoirs where the sample was retained when the flow was forced to pass through them, Fig. 3. Just after the sample catcher, the gas-liquid-solids mixture entered the Petrobrás vertical, two-phase separator. This cylindrical separator is 6-m high, has a 20-in. diameter and is built with two concentric pipes. The mixture enters the separator tangentially at its top. From there, the flow moves downward, passing through the annular of the two concentric pipes in a helical trajectory.
In this movement, the gas is separated, goes inside the inner pipe to the top of the separator and then proceeds to a secondary separator that retains any liquid still present in the
mixture. After that, the gas goes to the burner. Conversely, the liquid-solids mixture goes to the separator bottom and from there to the skimmer. The separator works with a liquid seal (to avoid gas going to the skimmer with the liquids-solids mixture). Pneumatic valves automatically control the liquid seal's level.
The skimmer receiving the liquids-solids (drilling fluid, oil and cuttings) mixture has three tanks able to collectively hold 280 bbl. The first tank holds cuttings, and the other two separate oil from the drilling fluid.
DATA ACQUISITION SYSTEM
A dedicated, fully automated control system was developed and used during operations to control all parameters, as well as opening and closing control valves. A typical screen from the data acquisition system is shown in Fig. 4. In this case, the screen shows a zero liquid level inside the separator. This was before the operation. All equipment and valves are displayed in a manner that makes it very simple for the operator to control the whole process from the control cabin. Another monitor was remotely located at the driller's cabin that allowed the driller and rig floor personnel to follow the operation.
Meanwhile, when the data is shown in real time, it is also being recorded for future analysis. An example of some data plotted against time is shown in Fig. 5. Contrary to other standard UBD operations, this data set is more complete, including separator levels, pressures and actuation of the control valves. Also the system was linked to the
MWD/PWD (pressure while drilling) tool. The list of recorded parameters includes: • Injection liquid and gas flow rates
• Injection temperature and pressure • Rotating control head pressure • Separator liquid level
• Liquid and gas outlet flowrates • Separator work pressure • Outlet liquid density
• Control valves' percentage openings • Bottomhole pressure
• Well depth.
Therefore, full control of the operation was in place at all times, even including observation of the influence of surface equipment on BHP. In many instances, when this is not possible, BHP might be above the desired value due to mishandling of chokes or valves at the
surface. With this automated control system, some operational practices were changed to avoid overbalanced conditions. Since the separator and control system were new, some of
the practices implemented were different from current ones, improving the whole operation significantly.
Alarms were in place for liquid injection, separator liquid level and separator work pressure. This allowed a much safer operation.
OPERATIONS
To save stand-by time for equipment and personnel dedicated to underbalanced operations, it was decided to batch drill the four wells. Therefore, the horizontal sections were drilled only after the four wells had been drilled and cemented to the intermediate casing string at a 90° inclination.
Attempts to avoid an overbalanced condition after the connection, by using a gas pre-charge after shutting in the liquid, were not practical. This was due to difficulties in coordinating the mud pumps and extra time required for gas injection. This was especially difficult due to the wells' shallow depths. Conversely, closure of the emergency shutdown valve at the surface, to avoid reduction of BHP below the collapse pressure, caused a sudden pressure increase and big slugs that impaired separator performance.
During the first well, actual collapse pressure was lower than predicted. Consequently, after connection, BHP was allowed to go to a lower value, just by shutting in the injection without any special procedure. Accordingly, the pressure increase after the connection was not as high as the simulator predicted. Even though an underbalanced condition was not always guaranteed, only during small periods of time did BHP reach values slightly above the estimated reservoir pressure.
Due to a problem on the nitrogen injection flowrate, which indicated a wrong value, the first well was drilled overbalanced during a majority of the horizontal section's initial portion. It was first supposed that the PWD was registering a wrong value, but, after everything was checked, it was concluded that the nitrogen flowmeter was wrong. Because oil production was being achieved - and half of the horizontal section had already been drilled - it was decided to keep BHP at the same level to avoid affecting formation stability.
The chart of BHP, and estimated collapse and reservoir pressures, can be seen in Fig. 6. In the remaining wells, this problem was solved, and the underbalanced condition was more stable.
Another interesting point to mention was a sudden, unexpected huge slug of nitrogen during the last third of one of the wells. A detailed investigation was conducted on all the measured and recorded values, and no apparent reason was found. One possible
explanation might be gas accumulation on the upper side of the horizontal section. At a certain point, the gas slug suddenly migrates to the surface. This phenomenon deserves further investigation, as it can cause serious problems during underbalanced operations. Total drilling time for each well ranged from 8 to 9 hr., except for the first well, which took 13 hr. In the same field, four other horizontal conventional wells were drilled recently, and the average drilling time for each horizontal section was 13 hr.
Oil production achieved during drilling averaged 150 bpd. Due to the oil's relatively high viscosity, skimmer efficiency was poor. Heating up the oil or adding some chemicals could have helped the oil/water separation, but these measures were not attempted. Oil content in the drilling fluid increased to 10% at the end of the well from the initial 0% value.
The well was planned for UBD and completion. Accordingly, a great effort was made to change the original well design, casing and cementing practices, and casing cleaning. After the slotted casing was cemented, from the intermediate casing shoe to the surface, the remaining cement plug and the slotted casing were washed and cleaned with nitrogen to avoid overpressuring the formation. Significant oil production during this period was observed.
At this time, it is not yet possible to check well production performance in comparison to other wells drilled conventionally. The idea is to measure not only oil output but also productivity improvement, to verify the benefits of drilling wells underbalanced. Higher fluid levels were observed inside wells after they were drilled underbalanced, so it can be concluded that formation damage was lower than usual. Quantitative measurements will be conducted as soon as production reaches a steady state.
CONCLUSIONS
This project was a successful venture by an integrated team comprised of personnel from different areas - drilling, reservoir engineering, geology, research and service companies. Integration of the team from the initial stages of planning, through training and field operation, was a key factor in the project's success.
After this first underbalanced campaign, one can conclude that UBD is a feasible
technique, even in an unconsolidated formation. To cope with this more aggressive drilling practice, wellbore stability analysis should incorporate new failure criteria and methods. Current wellbore stability simulators tend to be very conservative.
Both hydraulic simulators used - the steady state and the transient models - were accurate enough compared to field data, and were very important during the well planning stage. The automated data and control acquisition system is essential for having a safe, successful UBD operation. The new compact vertical separation was approved, and this same concept was used later offshore during a field test of drilling with lightweight fluids.
Preliminary results indicate an increase in productivity from the wells drilled underbalanced, compared with conventional wells.
The concept of cased drilling is to drill the hole with casing instead of drill pipe. The casing is then permanently installed in the hole. The casing is in place when the casing set depth is reached.
Photo:Tesco
Bottomhole assemblies are delivered by wireline, eliminating trips in and out of the hole with a drillstring. If the hole is dry, the last string of casing is recovered instead of being cemented in place. Wells can be completed quicker with no tripping and reduced pipe handling thus making it safer. The wellbore integrity is preserved. Reaming is not required. There are no kicks while tripping the drill string.
Photo:Tesco
The expenses for drill pipe, drill collars, large setback areas if running double or triple rigs are also eliminated. There are lower mud and cementing costs due to the smaller wellbore. The rig move is easier, cutting fuel consumption and equipment wear.
Casing drilling can reduce the time needed to drill a well by 20 to 30%, since the
conventional rig is more designed for tripping than drilling. Hole problems resulting from surge pressures and swabs are also removed. A Casing Drilling Rig only requires a Range III single mast. This rig can drill as fast as a conventional rig (though it may be slower in soft rocks. There is less circulating and back reaming at connections when drilling with casing.
Casing drilling has 25% fewer connections because casing joints are longer. Time not spent drilling on conventional rigs takes 44 to 86% of total well time. Casing installation and tripping account for 34 to 58% of this total.
Casing drilling uses the standard oil field casing to drill and case the well simultaneously. The casing provides the hydraulic and mechanical energy to the drilling assembly
suspended in a profile nipple located near the bottom of the casing. The drilling fluid is circulated down the casing and back up through the annulus.
Photo: Tesco
The bottomhole assembly latched into the bottom joint of casing is run and retrieved through the casing using a wireline (and not tripped with drill pipe-reducing costs). There are tools for the bottomhole assembly and drill lock assembly that secures the bottomhole assembly to the casing. The drill lock assembly gives the mechanical coupling and hydraulic seal to the bottom of the casing. It has a locator mechanism, and axial lock and torsional drive splines that mate with a profile nipple at the top of the first joint of casing.
Photo: Tesco
The drilling assembly below the drill lock assembly ends in a pilot bit, but can include other conventional drillstring components, such as a mud motor, underreamer, coring or directional assembly.
An underreamer above the pilot bit is normally used to open the hole to the final wellbore diameter. These are sized for casing drilling (e.g a 6 ¼ in. pilot bit and 8 ½ or 8 7/8 in underreamer are used while drilling a 7 in buttress thread casing).
The Casing drilling rig uses a top drive to rotate the casing. Single joints of casing are picked off the pipe rack and set into the mouse hole.
Photo: Tesco
The top drive is connected to the top of the joint which is then stabbed into the top of the casing string in the rotary table and drilled down. The casing string is attached to the top drive with a Casing Drive System that eliminates the need to screw into the top of the each casing joint. This replaces the power tongs, and adapts to all top drives.
The top drive rotates the casing at speeds similar to conventional rotary drilling. For directional and horizontal wells, the bottomhole assembly is equipped with mud motors and MWD tools (which are protected inside the casing). Torque rings can be included to increase the torque ratings of connections. Centralizers are also run.
Photo: Tesco
The biggest remaining need is to have an effective way to do logging through casing pipe. The most common method is to hoist the casing above the zone of interest and then run conventional wireline logs.
Drilling Program at Cold Lake CSS
A deviated well is any well where the bottomhole location is drilled at a horizontal offset from the surface location (wellhead). Cold Lake CSS wells are almost always deviated, since the bottomhole targets are drilled from a centrally located surface location.
Through ongoing development at Cold Lake, the length, bottomhole angle (well deviation) and pumping capacity of deviated wells have increased. Conditions now require some wells to exceed 1000 m in length, with a 750 m horizontal offset from the wellhead to bottomhole target and an 80 degree angle at the target. Recent additions to Cold Lake CSS well designs include using short horizontal wells on some pads. Short horizontal wells typically access the equivalent of two or three deviated CSS-well bottomhole locations. About 20 m to 30 m of conductor pipe is commonly present on each well before the well is directionally drilled to target depth and logged, if required. Production casing (typically 177.8 mm L-80 with metal-to-metal seal connections) is then installed from target depth to surface. Wells are cemented back to surface with thermal cement. Cement tops are maintained at surface to reduce the potential for external corrosion.
Surface casing is usually only installed on the first well drilled to confirm that the Clearwater Formation pressure is low enough to enable the remaining wells on the pad to be drilled without surface casing. Surface casing is set into competent shale below the glacial till and cemented in place with thermal cement. Alternatively, previous evaluation wells on or near specific pads are used to confirm that Clearwater Formation pressure and wellbore drilling conditions are suitable to drill selected pads without installing surface casing on the first well.
Directional Control
Wells are drilled using a downhole motor with a bent housing. To achieve directional control, a measurement-while drilling tool is used. Typical survey intervals are at:
• no more than 30 m in the vertical hole section • every connection in the build hole sections • 30 m in the hold hole and tangent sections
Hole Section Interval Planned Constraints
Vertical Section surface to kickoff point – typically 25 m true vertical depth
none Build Section 1 within the glacial till to
typically 130 m maximum dogleg of 3 degrees per 30 m Build Section 2 below the glacial till, as
required maximum dogleg of 10 degrees per 30 m
Hold Section after build section 2 maximum dogleg of 10
degrees per 30 m Tangent Section from end of hold section to
final total depth
maximum dogleg of 3 degrees per 30 m
Factors Affecting Drilling
Formation factors that affect the quality of the drilled hole include:
• gravel and boulders in the glacial till, which cause rough drilling for the first 60 to 80 m
• bridges in the glacial till, which make it possible to start a new hole while attempting to work the drill string through bridges in the original hole. To reduce the difficulty of re-entry, planned wellbore doglegs are kept less than three degrees per 30 m in the glacial till whenever possible.
Casing Installation
On all wells, 20 to 30 m of conductor pipe is preset to provide a stable wellbore for drilling operations. For wells requiring surface casing, the casing is typically set into a competent shale below the glacial tills, or at about 150 m. Production casing is installed after the well is drilled to target depth.
Each CSS well is cased and cemented with thermal cement from total drilled depth to surface. In the production casing, metal-to-metal seal connections is used to provide connection integrity. The casing is sealed at the surface by a thermal wellhead for steam injection and production operations.
Short Horizontals
At specific locations, short horizontal wells are used to access two or three bottomhole locations from a single wellbore. A horizontal extension is drilled after installing a standard CSS well to an initial bottomhole location. The standard well is drilled and cased to an inclination of 85 to 90 degrees at the initial bottomhole target.
Casing Grade
API 5CT L-80 Type 1 or equivalent proprietary grad steel is used in production or intermediate casing strings.
Casing Centralizers
Casing centralizers are installed on the outside of the casing to centre the casing in the borehole. Casing centralization is important for achieving good mud displacement while cementing, particularly from the narrow side of an eccentric annulus. Currently, centralizers are installed on every joint of casing from the surface down to the top of the Clearwater Formation. Two centralizers are installed on every joint across the Clearwater Formation.
Horizontal liners are typically set in an open hole, without cementing. Horizontal liners access the reservoir through perforations and wire wrapped screens.
Depending on the required well capacity, casing and production-liner designs use either: • a 219 mm production casing and a 140 mm production liner
• a 244 mm production casing and a 178 mm production liner
Production casing size depends on wellbore configuration. Depending on the production and injection requirements, the production casing size varies from 140 to 244 mm in diameter.
Production liner is a type of casing used in a lower part of a well.
Where short horizontal wells are used, standard wellbore configuration requires a 114.3 mm diameter production liner to be run from the base of the 177.8 mm diameter intermediate casing to total drilled depth and set in the horizontal section. The liner, normally:
• is set in the open hole without cementing
• is equipped with perforations and wire-wrapped screens
Metal-to-metal seal casing connections are used to provide improved connection integrity throughout CSS operations.
Imperial oil CSS developments typically use pads with 24 to 28 wells. Single bottomhole locations will cover 3.2 ha.
Directional Tool Inaccuracies
WELLBORE POSITIONING—
Calculated borehole position may be erroneous in over half of the horizontal wells drilled during the past 15 years, according to the results of an ongoing industry study of
continuous vs. stationary survey measurements. In a typical horizontal well, positional error of as much as ±25 ft true vertical depth (TVD) can accumulate. This study found that several generally accepted directional drilling and well surveying practices are primarily responsible for these errors.
The directional well surveying industry has used the minimum curvature method as its standard means to calculate the position of a wellbore from stationary inclination and azimuth measurements, and the distance between surveys has crept up from 30 to 90 ft. The assumption in the minimum curvature method is that there is a constant radial arc of curvature between survey stations.
This study of continuous direction and inclination survey measurements taken over significantly shorter intervals has found many instances where the constant radial arc assumption was not valid and in each instance resulted in a small positional error. In cases where the positional error was systematically repeated en route to total depth, a significant overall error resulted.
The accumulation of large positional errors during drilling can lead to poor and costly geosteering decisions that ultimately result in poorly placed wells, unplanned sidetracks, and lower recovery of reserves. The biggest impact of such errors to an operating company may be the mistaken addition or subtraction of hundreds of thousands of barrels of booked recoverable reserves per well.
Four sources have been identified that cause nonconstant curvature to occur between relatively long-spaced, 90-ft survey intervals. They are directly related to the mechanical aspects of directional drilling. The simple, short-term solution to reduce the amount of accumulated error is to take more surveys, although this will add to project cost.
Alternately, a long-term solution is being developed that will allow real-time monitoring of directional tendencies and borehole position using continuous direction and inclination measurements.
This three-part section includes:
• Part 1: A look at where positional inaccuracies occur in horizontal wells and how frequently they happen when drilling with a conventional steerable, positive-displacement motor system.
• Part 2,: A review of similar inaccuracies while using rotary steerable systems and (or) encountering lithology changes.
• Part 3: A set of recommendations and techniques that can help to minimize the problem.
Illuminating the problem
The minimum-curvature method has long been used as the standard means to calculate a wellbore's position from inclination and azimuth measurements by determining the smallest radius curvature between two survey stations. The black curve in Fig. 1 illustrates this assumption.
In this example there are two surveys, X and X+1. The position coordinates of Point X are given. The position coordinates for the second survey point, in terms of easting (X),
northing (Y), and true vertical depth (Z), are calculated by fitting a constant radial arc to tie the two positional vectors together. The inherent assumption with this method is that the entire section will be drilled at a constant radius of curvature.
The late 1980s introduction of positive displacement motors (PDMs) with bent housings to the directional drilling market made it possible to freely switch between slide drilling with high curve rates (5-10°/100 ft) and rotary drilling with curve rates usually less than 1°/100
ft. Further, top drives on offshore and some land rigs have enabled drilling with three, 30-ft joints of pipe (a stand) without stopping to make connections.
As initial measurement-while-drilling (MWD) tools took three-axis, stationary directional measurements when the mud pumps were cycled off and on during connections, surveying intervals have also increased gradually to 90 ft from 30-ft spacing. Bottom line, the advent of PDMs and top drives has increased the probability that curve rates will vary dramatically between stationary survey points; that is, nonconstant curvatures will exist. Simply
interpolating between these points will not reflect many of today's actual wellbore trajectories.
The blue, green, and red curves shown in Fig. 1 represent the alternate well path
trajectories that end up with the same measured depth, azimuth, and inclination for Point X+1. These are based on different combinations of sliding and rotary drilling between the two survey stations.
In each case the arc length and radius of curvature for each curved slide-drilled section are the same (shown as dashed line sections). However, the placement of these curved sections is varied from being before (blue), in the middle (green), and at the end (red) of a rotary-drilled tangent section of hole (solid lines). The model illustrates the importance of knowing where changes of curvature exist along a well path trajectory.
In the late 1990s, MWD service companies modified their downhole data streams to include sampling of accelerometer and magnetometer data during pumping operations, especially drilling. Simplified single-axis surveys now can be transmitted to the surface in the same way that gamma ray and resistivity data are transmitted. Specifically, continuous direction and inclination measurements (cDNI) are made every 30-90 sec, which results in surveys that are 2-4 ft apart when drilling.
These continuous data are being used routinely by directional drillers for trajectory tendency work. However, continuous surveys are not yet deemed reliable enough to be used as definitive positional surveys, as work on error models for the cDNI data continues.
Fig. 2 compares stationary and continuous survey data over a 500-ft build section in a directional well. The straight lines connecting the stationary survey points, both inclination and azimuth, indicate a constant rate of curvature.
The slope changes of the continuous inclination data indicate the vertical build and drop rates achieved while slide drilling vs. rotary drilling, respectively. The PDM motor delivered about 13°/100 ft building when sliding with the gravity tool face (GTF) settings given. The bottom hole assembly (BHA) dropped at about 4°/100 ft when rotated, which is a dramatic but not unusual occurrence resulting from a less than optimal choice of BHA. The curve rate calculated between the stationary surveys using minimum curvature is about 3.5°/100 ft. Following are details of how these differences in assumed versus actual
curvature rates result in positional error. Causes of positional error
Four primary sources of nonconstant curvature between long-spaced stationary surveys have been identified:
1.Slide or rotate directional drilling patterns accomplished with PDM steerable systems during the build, drop, and (or) turn sections of wells.
2.Systematic use of PDM steerable systems to compensate for build, drop, or walk tendencies when attempting to maintain or hold constant inclination and azimuth in a tangent well section.
3.Changing modes with rotary steerable systems between stationary survey points. 4.Lithology and (or) bed dip angle changes between stationary survey points.
Currently, concerns about wellbore position concentrate on differences in TVD. The positioning of a horizontal drainhole relative to fluid contacts and the construction of geological structure maps are based on TVD position. Changes in azimuthal location, while a valid concern, are of lesser importance at this stage.
Continuous direction (or azimuth) measurements have a wider fluctuation than continuous inclination measurements, as seen in the character of the Fig. 2 data. Thus, this article focuses on differences in TVD position, but the argument can be made for both TVD and azimuthal position.
Slide or rotate patterns
Fig. 2 shows a good example of applying a slide or rotate drilling pattern during the build section of a well. In this case the directional driller sets up a relatively consistent pattern of alternating between slide drilling and rotary drilling once per stand.
Fig. 3 shows three sets of slide (rotate) drilling models. Each case uses a series of 50-ft slide sections (building at 10°/100 ft) and 50-ft rotate sections with no build rate to go from an initial inclination of 0° to a final inclination of 90°. The position of the 100-ft stationary survey stations (yellow squares) is varied from being immediately after (A), in the middle of (B), or immediately before (C) a slide interval. The red squares show the continuous survey dataset for each of the models.
The difference between the TVD calculated using the stationary and continuous inclinations accumulates, as shown for each of the three modeled wells by the curves labeled A', B', and C'.
These show a swing of ±25 ft of accumulated TVD error. Note that when the slide section is placed in the center of the rotary drilled sections (B) the TVD errors cancel out (B'). While in practice directional drillers do not execute the perfect patterns shown, systematic patterns do present themselves.
A field study
There is no standard set of procedures for incorporating continuous directional data into survey calculations for dogleg severity or hole positioning. To determine the extent of wellbore TVD error resulting from slide/rotate drilling practices, a study was
Stationary and continuous survey data for thirteen horizontal wells in Nigeria, Angola and Indonesia were captured and processed. Directional operations data, BHA reports and slide sheets also were gathered.
Fig. 4 illustrates the general positional results of the study. (More detailed results can be found in Stockhausen and Lesso.1) Eight of the wells had TVD differences greater than 5 ft.
The largest difference recorded (Well GBK "a") showed that continuous inclination placed the final TVD 22 ft deeper than the TVD calculated from the stationary surveys.
The three smallest positional errors recorded were in wells AMP "a," BKPorg, and BKPst1, which were drilled in Indonesia with rigs without top drives and using a standard kelly. While these wells were being drilled, surveys were taken at every joint of pipe, about every 30 ft, and slide (rotate) section lengths varied widely.
The shorter survey interval of 30 ft did not allow for large differences between the continuous surveys and the minimum curvature assumption to accumulate. Top-drive use in the other countries allowed for larger difference in inclination to accumulate between surveys, and thus a greater chance for TVD differences to occur.
Fig. 5 shows the stationary and continuous inclination data for one of the Nigeria wells. The data cover the entire directional well from kick-off to TD at 9,033 ft. TVD calculations from continuous and stationary surveys had a 22-ft difference—deeper on the continuous survey. The delta TVD curve reveals how the error accumulated to reach a maximum difference of 23.7 ft at 7,310 ft MD.
Details of the same well between 6,000 and 7,000 ft MD, in its final build to horizontal, reveal the true nature of the slide (rotate) pattern used (Fig. 6). Continuous inclination data
show that angle builds while sliding and holds during rotary drilling. The stationary inclination survey points, taken at about 90-ft intervals, do not see this effect.
The line drawn between the stationary inclination points indicates the constant rate of curvature assumed by the minimum curvature method.
When the nonconstant curvature shown by the continuous surveys is below this line, the delta TVD accumulates, indicating that the well is increasingly deeper—or shallower when above the line. From 6,000 to 7,000 ft the overall delta TVD accumulates from 14 to 23 ft deeper.
It is important to note that in this well (Fig. 5) almost all of the TVD difference occurs as a result of attempting to build or drop angle. During the drilling of the hold sections (3,600– 5,700 ft and 7,100–9,033 ft), the BHA did a good job of holding angle when rotary drilling. The continuous inclination tended to directly overlay the line connecting the stationary surveys and little or no delta TVD developed. Only when correction slides were made (near 4,700 and 7,700 ft) did TVD differences occur.
Two conclusions arise from this study:
1. A significant positional error is possible on 60% of horizontal wells studied. 2. Positional error can be greatly influenced by directional drilling procedures.
The probability is high that horizontal wells drilled with PDM steerable systems on a top drive rig will have a TVD positional problem large enough to cause well-placement problems. The obvious criticism of these conclusions is that 13 wells are not a large sample.
Additional wells have been reviewed from the study area, as well as from the North Sea and Gulf of Mexico. The process is ongoing, but to date the percentage seems to be holding.
Landing horizontal wells
TVD positional differences in horizontal wells, caused by nonconstant curvature in surveys, can lead to poorly placed drainhole sections or missing the target reservoir
completely. Because neither operator nor service company personnel are typically aware of this problem, poorly placed wells usually are attributed to an unexpected change in
geological structure.
An earlier study by Lesso and Kashikar2 noted that about 40% of horizontal wells
encountered a "geological surprise" that resulted in a 10-20 ft TVD shift. With current knowledge in hand, it is interesting to speculate on how many of these shifts actually were caused by nonconstant curvature in survey calculations.
During geosteering operations, marker beds above the target reservoir are used to help determine wellbore position relative to the target. Trajectory adjustments are made accordingly, assuming that the vertical thickness and dip angles of the intermediate beds remain constant.
Petrophysical data modeling and navigation techniques developed over the last decade have made it possible to deal with most unexpected changes by maneuvering the drill bit to land the horizontal wellbore on target. But, additional TVD positional error can accumulate during the final approach to target, resulting in overshooting or undershooting the desired location and perhaps losing some lateral section.
WELLBORE POSITIONING—
Rotary drilling with positive-displacement motors can introduce positional inaccuracies that remain undetected with stationary surveys and lead to potentially mistaken drilling decisions.
Part 1 revealed where positional inaccuracies occur in horizontal wells and how frequently they happen when drilling with a conventional steerable, positive-displacement motor system.
This article further illustrates positional issues using PDMs and then discusses rotary steerable systems and the impact of lithology on accurate well placement.
Tangent sections
A tangent section is the angle hold section in a standard slant or "S" trajectory, or the lateral section of a horizontal well. It is generally expected that when rotary drilling with a conventional steerable PDM assembly, the borehole angle and direction will be maintained.
However, it is sometimes necessary to use active directional drilling; that is, perform slide sections when the objective is to hold angle in a tangent section.
The build or drop and turn tendency of a bottomhole assembly (BHA) can change with differing formations and operational parameters such as flow rate, weight-on-bit, and rpm. To counter undesired rotary drilling tendencies, a directional driller can add short slide sections to the drilling sequence.
Fig. 1 shows a model of what stationary and continuous survey data can look like when rotary drilling a lateral section with a BHA that drops at 1º/100 ft.
To maintain the wellbore at 90º, the driller has added a slide section of 14 ft, building at 6º/100 ft, to neutralize a rotary section of 86 ft dropping at 1º/100 ft in a 100-ft drilling section.
Here the slide is placed immediately after the stationary survey depth. All stationary surveys read 90º when this pattern is repeated, and it would be assumed that the wellbore is perfectly flat.
The continuous surveys show the actual inclination for this pattern and have values greater than 90º, except at the stationary survey points.
The wellbore TVD position calculated from the continuous surveys will drift shallow as compared to the position calculated from the stationary surveys. In this case the drift rate is 3.7 ft/500 ft drilled.
The Fig. 2 models demonstrate how this drift can impact decisions in drilling a horizontal well.
Fig. 2a shows the well trajectory interpretation that likely would result using stationary surveys to guide the planned placement of a 1,500-ft lateral section below the top of a relatively horizontal pay zone and above the oil water contact (OWC).
The stationary surveys show that the wellbore has been held at 90º with no change in TVD, yet the wellbore exits top of pay after drilling only 810 ft. The logical conclusion would be that the formation dips downward. Drilling would be stopped, and recoverable reserves estimates would be lowered since the full, 1,500-ft lateral drainage field was not achieved.
Fig. 2b shows the interpretation with the same drilling scenario using continuous surveying in a post-mortem analysis. It indicates that the well path had drifted upward and that the original structural interpretation was correct.
By monitoring well position in real-time with the continuous (cDNI) measurements, one can avoid negative scenarios like these in the future.
Fig. 3 shows an actual case of using slide sections to compensate for a rotary dropping tendency during planned hold sections.
Relatively long slides maintain approximately 90º to offset a relatively strong dropping tendency while rotating the BHA.
This well was eventually sidetracked when the top of pay was encountered earlier than expected.
Rotary steerable systems
Rotary steerable (RS) systems have eliminated the need for large curve rate changes between slide and rotary drilling sections, which are required with steerable motors. RS systems produce curve rates by selecting a tool face angle and percentage of side force in the direction of the tool face angle.
To increase angle and turn slightly to the right, a tool face of 20º could be used with 35% of total force available.
The power setting would be changed to 100% in order to steer more aggressively. A neutral setting of 0% and the tool face angle would be irrelevant.
Directional drilling with an RS system can produce long, consistent curve rates that are smooth and predictable. These systems also allow greater overall penetration rates for a well; however, a TVD difference can develop when settings change between survey points, as in Fig. 4.
That figure shows an example from a North Sea well during its final build to horizontal. A bit run with a steerable motor finished at about 3,100 ft and was followed by an RS run. Four different tool settings were subsequently applied over the 3,100-4,000 ft interval. The continuous inclination measurements demonstrate the consistency in build angle for each set.
Stationary surveys were taken after drilling each pipe stand. In two cases the steering settings were changed between stationary survey points resulting in an apparent "rounding the corner" effect between the continuous and stationary inclinations.
Such corners can cause up to a 2-ft TVD difference-occurrence and in this case accumulated to about a 3-ft TVD difference.
Effects of lithology
Lithology changes such as tight streaks, changes in rock strength, and changing bed dip angle can alter directional tendencies.
When these are encountered between survey stations, a rounding the corner effect, similar to what happens with RS systems, can result in TVD positional differences.
Typically isolated incidents, these events are difficult to detect with long survey intervals. Tight streaks can result in a large dogleg over a short interval and cause drilling and completion problems in addition to TVD differences.
By monitoring the cDNI data in real-time, these events can be identified and remedial action taken to minimize their effects.
Fig. 5 shows the reaction of an RS drilling assembly with a high-density tight streak in a horizontal wellbore. The trajectory decreases to 82º from 95º inclination while drilling a sinusoidal horizontal well profile.
The bit hits the bottom of a hard streak at 5,750 ft and bounces down, as shown by the continuous inclination. Bottomhole assembly (BHA) stiffness causes the inclination to recover and the bit hits the hard streak a second time before the general downward tendency in inclination continues.
The stationary surveys do not register this event. In this case, the TVD positional
differences cancel out. The dip interpretation, using an image log and stationary surveys, would indicate folded beds and dip changes. Interpretations of continuous surveys, on the other hand, would indicate that the bed dip is constant and the wellbore is kinked.
Changes in directional drilling and surveying practices could lead to a reduction in positional errors arising from nonconstant wellbore curvature.
While drilling, postdrilling surveys
Many have believed that the nonconstant curvature caused by slide and rotate drilling with PDMs is reamed out by pipe rotation and tripping actions as the well progresses. Some have thought that wellbore tortuosity and positional difference were thereby eliminated, resulting in a smooth borehole. This assumption was long unquestioned until continuous surveys made while drilling could be compared with continuous gyro surveys taken after drilling each section.
Fig. 1 shows stationary, continuous measurement-while-drilling (MWD), and continuous gyro inclination survey data from a 1,000 ft, 121/4-in. diameter section of a North Sea well. Angle was built during the slide sections and held during rotation, as previously