240 VSP levels were shot to enable accurate time/depth correlations with surface seismic as well as formation velocity confirmation. (Images courtesy of Schlumberger)

Marathon’s Droshky field lies in Green Canyon Block 244 offshore Louisiana. It is a recently discovered deep Miocene oil play just above salt. Marathon is planning a multiwell development drilling program, the details of which will depend on the results of drilling and logging of a delineation well. Early in 2008 the delineation well, GC 244 #3, was drilled. The first objective was to drill downdip into what was believed to be an aquifer leg. Specifically, Marathon wanted to establish the field oil/water contact.

Following the initial borehole, two sidetracks were planned. One would go updip to evaluate multiple pay zones. Based on information gained from the first sidetrack, a second sidetrack would be drilled closely paralleling the first to allow conventional coring and PVT sampling. A production liner would then be set to allow the well to be completed as a producer at a future date. Casing was set around 15,000 ft (4,573 m) measured depth.

Unfortunately, problems were encountered in drilling the initial well bore. Several cave-ins were encountered. and sloughing shales resulted in drillstring pack-offs. Because of the risks presented by the well bore, Marathon elected to forgo wireline logging that included acquisition of vertical seismic profile (VSP) data as well as formation pressure data — information critical to achieving the well’s objectives.

Asset team members had a stake in log data needed to complete their portion of the field development plan. The plan would be based on a 3-D reservoir model tied back to surface seismic, and for that borehole seismic would be used to acquire accurate time/depth pairs to correlate the velocity model. Analysis of formation pressure tests was critical to understand reservoir connectivity. Final development well trajectories would depend on identification of optimum sand packages to exploit. The team members sought an alternate, less risky method to acquire the information they required.

The drilling engineers had determined that sands just below the casing shoe had a pore pressure of 11.5 ppg equivalent mud weight, while the casing shoe test tested to 15 ppg. This meant that further drilling must be attempted with the greatest care as losses might be experienced in the low-pressure sands. Both the downdip and updip excursions were important to provide the information needed to complete the reservoir model. An unplanned incident in the downdip well could jeopardize the ability to drill the updip sidetracks. For example, if high formation pressures were encountered necessitating the setting of a liner, it could make sidetracking to an optimum location more difficult and time-consuming, and therefore more costly. What had started out to be a fairly straightforward delineation well had become extremely challenging.

An integrated solution

In collaboration with Schlumberger, the asset team conceived a bold plan to acquire all the remaining information using a logging-while-drilling (LWD) tool string. Eight tools comprised the instrumented bottomhole assembly (BHA). A seismicVISION seismic-while-drilling tool was included to acquire VSP data during the logging of the first leg of the well. Formation pressure-while-drilling service was provided by the StethoScope tool — this information would provide drillers with vital pressure data to ensure drilling could proceed safely as well as help identify fluid types and pressures in key zones of the production interval.

A quad-combo logging string provided azimuthal resistivity compensated formation pressure-while-drilling and dual-fast-downlink configurable sonicVISION measurements.

Finally, a new ultrasonic caliper tool capable of taking measurements in 16 ppg mud was run to provide confirmation of borehole breakouts and hole ovality. Directional drilling for the sidetracks would be achieved using the 8.25-in PowerDrive X5 rotary steerable system (RSS). Critical log data were transmitted to surface in real time with the TeleScope high-speed telemetry-while-drilling tool, along with drilling parameters such as continuous direction and inclination, lateral, axial, torsional vibration, downhole weight-on-bit, and internal and annular mud pressures.

Since the main well bore had already been drilled, the first task was to log the existing borehole in wash-down mode. During this phase, seismic would be run. To maximize efficiency, seismic levels were shot while making drillpipe connections. As a result, critical seismic data were acquired without using any additional rig time. The first pass provided 90-ft (27-m) intervals, then one joint was removed and the string was tripped out of the hole, again shooting on every connection. This improved the data density from 90-ft to 30- and 60-ft (9- and 18-m) intervals.

A total of 240 levels were acquired, making this one of the longest LWD walkabove seismic jobs ever acquired. A walkabove survey requires that seismic sources deployed from a boat follow the well trajectory and fire vertically incident to the seismic tool in the BHA.

In all, 8,203 ft (2,500 m) of open hole in the main well bore was drilled and surveyed. The seismic data allowed company geophysicists to resolve critical time/depth correlations with the surface seismic survey. Even though drilling the salt was not an objective, it was possible to get an image from which the top of salt could be predicted.

Formation pressures, taken with the StethoScope tool while descending, gave drillers confidence that the objectives of the delineation well could be achieved safely. The tool had been equipped with several new features that proved valuable. A selectable time-optimized pretest (TOP) configuration enabled multiple pressure tests to be conducted in only five minutes with approximately nine minutes on station. This was beneficial in the unstable borehole as the drawdown forces were kept to a minimum. In addition, an on-demand frame feature (ODF) provided real-time images of the critical stages of the pressure test so enhanced quality control could be performed.

Engineers monitored the enhanced real-time data transmitted through ODF. In the event of lost seal or tight formation, the test can be repeated, assuring no lost well evaluation data. In total, 51 quality pressure tests were achieved with 85% sealing efficiency. A new feature of the tool included a mechanical caliper measurement made by monitoring the extension of the tool’s backup piston. This feature is used to enhance the understanding of the cause of potential lost seals. If the tool is fully extended, a seal failure is likely due to washed out hole; if only partially extended, the failure mechanism may be unconsolidated formation. The formation testing tool is then moved to areas that may be at the same depth but oriented to the other side of the hole or to another depth based on hole conditions. This caliper reading is a single-axis point measurement that can also be used to calibrate inferred measurements made by other tools in the BHA.

When drilling was terminated, the equivalent mud weight had reached 14.5 ppg. This was as deep as the drillers felt they could go without setting a liner and not experience losses in the low-pressure sand or at the casing shoe.

In addition to the formation pressure readings taken while tripping into the hole, the tool was used to record pressure gradient data that were used to derive fluid density, hence discriminate between oil and water zones. By extending adjacent gradient lines, oil/water contact levels can be interpreted. The gradient lines are used to establish the fluid density and as such provide additional information when interpreting zones. These interpretations were used to choose accurately the intervals from which whole core would be acquired during drilling of the second sidetrack well as well as those zones from which PVT-quality formation fluid samples would be obtained.

Once the required data were acquired, tools not needed for subsequent measurements were laid down as the pipe was tripped out of the hole. As a result, the second sidetrack was drilled mainly with a BHA consisting of only the arcVISION Array Resistivity Compensated tool and the TeleScope telemetry tool. The azimuthal density-neutron tool was added to the BHA for the last 1,000 ft (305 m) of the well.

Results benefited team members

The real-time pressure measurements were used to make decisions as drilling progressed. A chat network was established using the Schlumberger InterACT real-time Web-based networking portal between the rig, the Marathon office in Houston, the Schlumberger Operation Support Center (OSC) interactive drilling operations in Youngsville, La., and local Schlumberger reservoir domain experts in Houston. In collaboration, the asset team and Schlumberger engineers were able to validate that good formation pressure and drawdown/ buildup transients were being recorded. The pressure profiles were interpreted for quality in real time as well as providing all basic analysis. Once the recorded mode data was downloaded, the pressure profiles were further analyzed and composited with other measurements.

The TOP proved valuable because it maximized the amount of critical data that could be acquired during a tight time window. Due to the well conditions, the tool string was susceptible to differential sticking. It was determined that the BHA was not sticking; instead, it was the drill pipe just below the casing shoe. Because the drillstring could be moved after only a few minutes on-station, it was possible to rotate off the borehole wall to break the differential effect each time. During one of the subsequent trips, a pressure test was taken in the suspect low-pressure water sand. This information will be added to the drilling file so subsequent development wells can avoid problems by setting pipe across this zone in the future.

The seismic time-depth pairs allowed recalibration of the surface seismic velocity model, while the acquired VSP enhanced surface seismic over the imaged zone. The reservoir group is still evaluating the pressure data to resolve reservoir compartmentalization issues. Despite the difficulties presented by this challenging borehole, sufficient information was obtained to meet the company’s objectives on budget and with no major issues. The ability to make timely decisions with confidence mitigated the drilling risk. At every stage in the project the team was able to make and modify its plans with confidence.

The final result

With the data obtained in the GC 244 #3 well and sidetracks, Marathon is in the process of formulating various field development strategies. Pressure data, fluid characterization, and rock mechanics evaluations have led the company to recommend a sand management completion in each well.