Many economic hydrocarbon deposits underlying salt formations have been discovered in the Gulf of Mexico, including the Gemini field, located in Mississippi Canyon Block 292, about 90 miles southeast of New Orleans.
Two directional development wells were drilled successfully in the Texaco oper-ated Gemini field, one of the first deepwater subsalt development projects in the Gulf of Mexico. Limited reservoir information below the salt presented geological uncertainty that had to be overcome in order to meet targeted objectives.
Additionally, tough directional drilling challenges were successfully met, as demonstrated by drilling efficiencies achieved. These challenges included:
- Kicking off a well without a riser in large-diameter hole
- Controlling wellbore trajectory through more than 3,000 ft of salt
- Executing difficult sidetracks to revised bottomhole targets.
Project success has been attributed to the novel application of technology and to detailed directional drilling planning that took into consideration the appropriate geologic, engineering and economic requirements.
Subsalt reservoir development is a major challenge for oil companies from the standpoint of seismic interpretation and drilling operations. Formed over time by evaporating seawater, salt formations can accumulate to thicknesses of several thousand ft. Because salt is both ductile and impermeable, it can effectively trap oil and gas.
While salt retains its low density after burial, surrounding sediments tend to compact and become increasingly dense with depth. The resulting density and pressure variations can present difficult circumstances that drillers must overcome. Further, its high seismic wave velocity - about twice that of surrounding sediments - complicates seismic processing and interpretation.
Plan and section view of Well No. 3 shows planned and drilled trajectories.
Specifically, the salt-sediment interface presents a strong velocity contrast, which acts like an irregularly shaped lens that refracts and reflects seismic energy. When using early seismic processing methods, the contact appeared as a mirror that continuously extended salt images through the data's deepest level.
During the 1980s, seismic processing began to image more correctly the salt structures under which hydrocarbons could accumulate. Over the last five years, further advancements in seismic acquisition, processing and interpretation techniques have enabled the nuances of salt structures to become visible, more accurately imaging not only the top of the salt but its bottom and adjacent sediments, as well. However, the salt still presents limitations.
Allocthonous salts are believed to have migrated horizontally after reaching vertical equilibrium in their original locations. In the Gulf of Mexico, these geologic phenomena occur mainly in deepwater, where sediments are not as thick as the near-shore continental shelf. Numerous economic hydrocarbon deposits have been discovered underlying these salt formations, including the Gemini field.
Discovered in 1995, the Gemini field is located in Mississippi Canyon Block 292 of the US Gulf of Mexico, in 3,400 ft water depths. The field is a joint development project between Texaco (60%) and Chevron (40%). The No. 1 exploratory well tested the 11,300-ft true vertical depth (TVD) target interval, the Allison sand, at a rate of 32 MMcfd natural gas and 627 b/d condensate.
Upon this discovery, two additional wells (No. 3 and No. 4) were planned that included appraisal drilling not only for Allison sands, but also for deeper targets, the Dean and Erin sands at about 15,000 ft. All three wells would produce from a collective subsea system into a pipeline that was tied back to a neighboring platform.
Because local salt formations limited seismic interpretation of underlying reservoirs at this time, team geoscientists were looking to acquire as much downhole information as possible from the two planned development wells. Therefore, a water-base drilling fluid was selected to improve log data accuracy. However, hole stability would be a concern when using such a system, as the exploration well experienced problems that required synthetic oil-base mud to resolve. The team therefore developed a contingency plan to switch to an oil-base drilling fluid if similar problems were encountered.
The uncertainty inherent in the seismic interpretations available for this project pointed to the need for real-time formation evaluation using logging-while-drilling (LWD) measurements, which would be transmitted to the surface using a measurement-while-drilling (MWD) system. High data transmission rates would ensure directional control and safe, continuous operations without sacrificing borehole formation data. Constant updates would help the geologists to refine their geological model and push casing points for maximum benefit. Offset data combined with LWD and wireline data would help determine the best possible borehole placement.
Strongly influencing the design of the directional wells was the 7,000-10,000-ft depth of the salt formation. At these depths, a drillable wellbore trajectory that allows kicking off below the salt to meet targeted objectives is impossible. Thus, the angle-build had to be completed before entering the salt, requiring a relatively shallow kick-off depth with respect to the mud line at 3,476 ft. Moreover, an S-shaped directional well profile was needed because the deeper targets were directly below the Allison sand. The well plans specified the following casing requirements:
- 36-in. conductor jetted 250 ft below the mudline
- 20-in. surface casing
- 16-in. casing set into the top of the salt
- 11-in. casing string set just below the salt, casing it off prior to drilling the reservoir
- 9 5/8-in. liner across the reservoir to accommodate the expected flow rates.
Since the No. 1 well had no shallow water flow, it was not expected in the subsequent wells. Therefore, plans called for the 24-in. intervals to be drilled without a riser.
Building angle in the weak shallow formations dictated the use of low-angle (no more than 2 degrees/100 ft) build-up rates. It also required a shallow kick-off point in the 24-in. section. While this is not typical practice in Gulf of Mexico deepwater operations, it has been applied successfully in many other areas. However, shallow kick-offs typically are executed at lower build-up rates. Therefore, plans included building angle at 1 degree/100 ft from the 24-in. kick-off point to the 20-in. casing depth, and continuing at 2 degrees/100 ft through the 17-in. by 20-in. section until reaching the 16-in. casing depth point at the salt interface. Achieving planned build-up rate in the 24-in. hole section and dropping angle in the salt formation toward the target was key.
Whether the directional work could be achieved by simultaneously drilling and under reaming was brought into question. Drilling motor use limited the team's options to drilling a pilot hole and then under reaming, or drilling with a bi-center or steerable reaming-while-drilling tool. Because the latter option would allow less directional control, the former option was selected-to first drill and then underream at casing point.
A 14-in. hole was planned for the salt formation, where the drop-off for the S-shape profile would begin at 1.5 degrees/100 ft. The final S-shape well design was to reach maximum angle at the 16-in. casing shoe depth, the angle dropping back to vertical at the Allison sand target. The No. 3 and No. 4 wells were to be drilled to azimuths of 55.3 degrees northeast and 307.3 degrees northwest, respectively.
Plan and section view of Well No. 4 shows planned and drilled trajectories.
The No. 4 development well was spudded first in early February 1999, followed by No. 3 about one month later. For both wells, 36-in. conductor and 20-in. casing were batch-set to maximize operational efficiency. A 24-in. jetting bottomhole assembly (BHA) that included an MWD tool and a 9 5/8-in. mud motor with bend set to 1.5 degrees was used to drill to kick-off depth. In both wells, the motor provided excellent directional response in the soft formations, which helped to limit hole angle loss while circulating off bottom and optimize drilling parameters for favorable and controlled build rates.
In well No. 4, a 16.8 degree angle was built by casing point at an average rate of penetration (ROP) of 47 ft/hr. Well No. 3 reached 13.7 degrees inclination at casing depth, at ROP (rate of penetration) averaging 54 ft/hr. Ninety hours were required for well No. 3, from tripping in with the 36-in. jetting assembly to the start of running the 20-in. casing, which is an improvement over the 104 hr required for the same procedures on well No. 4. This may have been due to batch drilling the section, applying fresh experience to the next well. The large-diameter (24-in.) kickoffs achieved planned build rates and exceeded expectations in terms of directional control, thus meeting the first major challenge of the project.
Once the 20-in. casing was set, a 17-in. pilot assembly was then used in well No. 4 with the same mud motor and bend setting in order to finish building the curve to 33.3 degrees at a 2 degree/100 ft rate. The BHA performed well. Drilling progress was enhanced by limiting sliding to 22.1% until the top of the salt. The ROP averaged 55 ft/hr before drilling into the salt, dropping to 15-18 ft/hr after salt penetration.
As the formations above the salt consisted of mainly gumbo clays, a downhole annular pressure measurement in the MWD string was used to monitor cuttings loading by calculating equivalent circulation density (ECD) while drilling. This procedure reduced the risk of packing off and sticking the assembly in the clays.
A 14-in. steerable BHA using the same motor, but with the bend set to 1.15 degrees, drilled the remaining 3,560-ft salt section while holding the 31.5-degree tangent to the drop point, and then dropping to vertical at 1.5 degrees/100 ft, rotating 84.1% of the total footage drilled. Drop-off through the salt was achieved as planned, the angle being reduced to 2.4 degrees at casing depth. The second directional drilling challenge had been met: drilling the salt in a single BHA run while maintaining trajectory control.
The same drilling equipment and methodologies used for drilling out from the 20-in. casing in well No. 4 were applied to well No. 3, which exhibited similar drilling performance but required more steering because of higher maximum angle. ROP was less than the No. 4 well, averaging 36 ft/hr before the salt, and then dropping to 17 ft/hr inside it. However, the under reaming procedure performed after reaching TD (total depth) was faster by about 5 ft/hr.
A bit change improved ROP significantly in No. 3's salt section. A milled tooth bit increased ROP to 35 ft/hr, compared to 25 ft/hr for the previous bit run and 28 ft/hr on well No. 4. After drilling a total of 2,813 ft in 87 hr, the bit was in good condition with its seals still effective. A low-speed, high-torque motor and 50 rpm to 70 rpm from surface indicated that the bit was turning about 160 rpm during the run.
Following the salt zone, a 10 5/8 in. by 12 in. reaming-while-drilling assembly with MWD/LWD tools and an 8-in. PDC (polycrystalline diamond compact) pilot bit drilled both wells to TD. Such an assembly has proven successful when steerable directional work is not required. It allows measurements to be made using 6-in. tools in the 8-in. pilot hole rather than the 12-in. open hole, which reduces annular mud volume.
Both wells were successful from a directional drilling aspect in that the targets were hit precisely. Unfortunately, the Allison target sand in the No. 4 well proved to be of poor quality. Additionally, hole problems in the No. 3 well associated with the water-base mud prohibited wireline logging, thus increasing reliance on LWD data. As a result, sidetracks were planned for both wells.
Planning the sidetracks
New targets to the northwest were planned for well No 3. by sidetracking below the 11-in. casing shoe, or at about 11,580 ft, with a 10 5/8-in. hole. Synthetic oil-base mud was selected to eliminate formation stability problems. The Allison sand remained the primary target, with continued drilling planned to appraise a Dean sand target about 1,000 ft to the west-northwest and then on to TD in the Erin sand. The new well path required a total turn of 130 degrees.
Well No. 4 required a new Allison target, which meant coming up the hole to get sufficient displacement. The new target was about 1,300 ft east and 500 ft north of the initial target. Geologic circumstances required opening a window in the 11-in. casing and sidetracking into the salt formation at a whipstock setting depth of 7,534 ft. This resulted in the drilling of about 3,000 ft of salt section and more complex directional work. The sidetrack was planned for a 10 5/8-in. pass through a 12-in. hole, turning through 70 degrees and setting a 9 5/8-in. liner below the salt.
Well No. 3 was re-entered, and a slick assembly was run to displace to synthetic oil-base mud, drill the abandonment plugs and retainer, and dress off the open-hole cement plug to 11,580 ft for sidetracking. Using a gyroscope survey for orientation, a whipstock was set in the 11-in. casing to sidetrack out of a window at 11,231 ft. The window was milled using a conventional three-trip milling system, since a one-trip system was not available.
The sidetrack BHA consisted of a 12-in. steerable reaming-while-drilling tool with an 8-in. milled tooth pilot bit run on an 8-in. mud motor with bend set to 1.5 degrees. The BHA was used to build 5.5 degrees of angle while turning at the planned dogleg severity of 1.75 degrees/100 ft. This bit run averaged 32.5 ft/hr with a sliding percentage of 34.5%.
After running the 9 5/8-in. liner below the Allison target, a new BHA was made up consisting of an 8-in. PDC bit run on a 6-in. extended power motor with bend set to 1.15 degree. This BHA was used to drill the 8 1/2-in. tangent section to intersect the Dean and Erin sands, rotating 97% and averaging 46 ft/hr ROP. Largely because of the synthetic oil-base mud, drilling performance improved in the No. 3 sidetrack, with ROP averaging 39.7 ft/hr compared to 16.8 ft/hr for the original hole.
A one-trip milling system was available for the well No. 4 work, and proved to save time while the synthetic oil-base mud from the No. 3 sidetrack saved money. Moreover, MWD orientation set the whipstock and mill assemblies to 42 degrees right of high side, which eliminated the need for a gyroscope survey. While some problems were encountered during the No. 4 window milling operation, which required two trips to solve, one less day overall was required to complete the well No. 4 procedure, as compared to No. 3, which employed the three-trip system.
Using the same sidetrack BHA, motor and setting, the No. 4 sidetrack, which extended 2,689 ft from a depth of 7,584 ft, took 99 hr to complete. The directional objective was achieved with an 18.7% sliding percentage and a 27 ft/hr average ROP. The milled tooth bit was pulled in good condition, which demonstrated superior ROP in the salt and minimized orientation time and sliding problems for both wells.
Tangent drilling through the salt was conducted with the existing BHA and a PDC bit. Salt base was reached at 10,716 ft, after drilling through 3,182 ft of salt. The PDC bit made sliding more difficult compared to the milled tooth pilot bit, lowering ROP to 10 ft/hr compared to 20 ft/hr for the first bit run. ROP in the salt averaged 26 ft/hr, increasing to 50 ft/hr through the remaining sediments.
Completed in only 11 days, the No. 4 sidetrack demonstrated exceptional drilling success, accomplishing for the first time in salt a sidetrack from a casing window using a steerable reaming-while-drilling assembly. In addition to proving the feasibility of appraising subsalt reservoirs using an initial pilot hole, the sidetracking success surely opens future multilateral development possibilities in subsalt reservoirs.
Two complete subsalt wells and two difficult sidetracks were drilled in only 165 days. Despite the S-shaped well profiles and demanding sidetrack turn requirements, nearly 27,000 feet of hole was drilled with a BHA rotating percentage of 80.1%, demonstrating excellent directional drilling efficiency.
In the drive for continuous improvement, efficiencies must be found and applied in future deepwater wells. Future opportunities include design improvements for both bi-center bits and steerable reaming-while-drilling tools, with the goal of drilling out of casing without damaging either the casing or the bit. ;
Many people at Texaco Exploration and Production and Schlumberger Oilfield Services made this project possible. Special thanks to the drilling foremen of Texaco Exploration and Production, the crew of the Ocean Star, and directional drillers and field engineers of Schlumberger Oilfield Services.
John R. Cromb III is a senior deepwater drilling engineer with Texaco Global Drilling, based in Houston. He has a BS in chemical engineering from Ohio State University.
Michael Long is the Directional Drilling Coordinator for Schlumberger, assigned to all Texaco projects on the Gulf Coast. He began his career in the Gulf of Mexico in 1979, and has been with Schlumberger since 1983.
Charlie Pratten is Directional Drilling Manager for Schlumberger North and South America. He has 23 years oilfield experience, the majority of which has been in directional drilling. He has a BSc in Mineral Exploitation from the University of Wales at Cardiff, U.K.
R. Alan Walters is a Sales Engineer in New Orleans, and has worked with Schlumberger for the past 20 years in MWD/LWD/DD services in the USA and elsewhere. He has an MS in geology from the University of Southern Mississippi.
Cromb, J., Pratten, C., Long. M., Walters, R.: "Deepwater Subsalt Development: Directional Drilling Challenges and Solutions," SPE Paper No. 59197, IADC/SPE Drilling Conference, New Orleans, Louisiana, February, 2000.
Farmer, P., Miller, D., Pieprzak, A., Rutledge, J., and Woods, R,: "Exploring the Subsalt," Oilfield Review (Spring 1996), 8, No.1, 50.