Full achievement of this objective has not been straightforward or quick. While good well productivity was seen from the early wells completed with MSF technologies, several technical issues had to be investigated and resolved when the technology was initially introduced. These issues included mechanical and differential sticking during the deployment phase as well as failure to attain a clear fracture signature for the subsequent stages after fracturing the first stage in carbonate formations due to potential hydraulic communication between the fracture stages.
Compared to other fields the world over, the application of MSF operations in Saudi Arabia has been typically more challenging and has required more sophisticated approaches due to the deep, highly heterogeneous, high-pressure, high temperature nature of the gas-bearing formations, as well as the high pumping pressure required and the large treatment volumes being pumped.
Accordingly, improvement strategies were implemented to mitigate these limitations and realize the full advantage of using MSF technologies in developing tight gas reserves. This article discusses these strategies and shows how they have been successfully utilized to further improve the application of MSF and surpass most of the original production expectations.
Furthermore, the article addresses a scheme for increasing the success rate for the secondary (contingency) coiled tubing (CT) ball seat milling out operations for MSF systems.
The article takes a holistic approach integrating the various technical disciplines involved in ensuring optimum results are obtained.
As early as 2007, the first open hole multistage fracturing (MSF) completion systems were being installed in Saudi Arabia’s deep, highly deviated wells located in high-pressure, high temperature, highly slanted, tight layered, gas-bearing formations exhibiting unconventional heterogeneity, Fig. 1. Only a handful of MSF technologies were installed in the early years while the benefits were evaluated. To date, about 50 MSF completion systems have been run to support the gas development program in Saudi Arabia.
The purpose of using MSF technologies has been to maximize reservoir contact, completely cover the production interval and ensure precise treatment fluid placement (1, 2), Figs. 2 and 3. Targets have spanned both carbonate and sandstone formations, with the number of fracture stages ranging from two to seven per lateral. The production results have varied, with the majority of the MSF wells meeting or exceeding the pre-stimulation expectations (1, 3-7). Also, three different MSF technologies were deployed by three different technology suppliers with differences mainly in the design of the isolation packers, the external pressure sleeve and the seat and ball material (3, 8).
Given the fact that Saudi Arabian gas reservoirs are more challenging than most other reservoirs in that they are very deep, extremely hot, highly heterogeneous and developed with complex well trajectories, many challenges had to be overcome during the early phase of applying MSF technologies in Saudi Arabia (6). The main challenges encountered included mechanical and differential sticking as well as hydraulic communication between stages in carbonate formations, preventing the creation of separate fractures in each stage of the completion assembly.
This article addresses the main challenges faced and describes the effective strategies that have been devised to mitigate these challenges and realize the full benefits of the MSF technologies. Also, the article reviews the production results for MSF wells and compares them to those of offset wells that have been completed using other techniques, such as horizontal open hole or cased hole.
STRATEGIES FOR PREVENTING MECHANICAL STICKING
A few of the early MSF technologies encountered mechanical sticking issues due to restrictions in the wellbore, especially in cases where the reamer used did not accurately and precisely mirror the open hole packer. The following strategies were developed and implemented to prevent mechanical sticking.
A specialty reamer was run to clean out the wellbore prior to running the MSF system. The specialty reamer mirrors both the size of the open hole packer to ensure good cleaning and the stiffness of the packer to ensure passage through the dogleg.
A detailed drag modeling program was used to simulate the drag forces imposed while running the MSF technologies downhole, Fig. 4. As MSF well candidates are identified from the beginning, the drag model is initially run using the planned well directional survey to evaluate the potential of running the MSF technologies to the target depth; any necessary changes in the directional plan are made based on the modeling results. Later, the modeling is performed again using the actual survey data to verify the potential of running the MSF system to the target depth as well as to optimize the deployment string design.
While it is true that longer packers offer higher differential pressure, given that other features of the packer stay the same, the packer should be short enough to minimize contact with the wellbore and pass any dogleg during the deployment, facilitating easier reach to target depth. Figure 5 shows a mechanical packer that has a dogleg severity of about 30°/100 ft as a result of its small radius.
STRATEGIES FOR PREVENTING DIFFERENTIAL STICKING
A few of the early MSF technologies encountered differential sticking because of the use of excessively heavy drilling mud as well as a large difference in pressure between two adjacent formation members, Fig. 6. For example, within the Khuff-B formation are six zones with different formation pressures, an environment that is prone to cause differential sticking. The following strategies were developed and put into action to prevent differential sticking.
A fluted centralizer was connected to the MSF technologies to enable positive standoff from the wellbore and prevent hydraulic lock. The centralizer is a slip-on type with a large water course and a swivel device to allow liner rotation inside the centralizer. This results in minimizing the contact between the wellbore and the MSF technologies while maintaining a good passage for fluids in the wellbore.
Mechanical Earth Model
For wells that had been drilled in the minimum horizontal in situ stress plane (σmin), a 1D Mechanical Earth Model (MEM) was used to foresee the formation pore pressure and provide the optimum mud weight to improve wellbore quality, leading to successful deployment, Fig. 7. The MEM is initially built using the logging while drilling (LWD) composite log and core data from offset wells. Then, the model is tested on the offset wells for verification and calibration purposes. Also, the MEM is calibrated while drilling in real time using the pressure data obtained from LWD measurements. A 1D MEM is used as opposed to a 3D MEM for the following reasons. First, it fits the purpose. Second, it does not require the amount of input normally required for a 3D MEM. Finally, it is cheaper. Along with the optimum drilling mud weight, the model also provides the mud weights at which formation breakout, kick, mud loss and breakdown are expected to occur. The use of the MEM eliminates any differential sticking issues by lowering mud weight in a safe manner.
STRATEGIES FOR MINIMIZING HYDRAULIC COMMUNICATION BETWEEN STAGES IN CARBONATE FORMATIONS
Clear fracture signatures were not observed for all the subsequent fracture stages after fracturing the first stage for some wells drilled in the maximum horizontal in situ stress plane (σmax) and completed across the Khuff carbonate (9). This setback was caused by hydraulic communication between the fracture stages due to natural fractures or the failure of the isolation packer to keep the pressure and fluid contained in the stage, resulting in a much shorter fracture length.
Several initiatives were put into action to mitigate the effects of this complex issue, such as a reduction in the acid volume and the use of a balanced system and anchoring tools. The acid volume reduction was recommended to minimize the eroding away of the rock matrix around the slips of the isolation packer, whereas the balanced system and anchoring tools were favored to prevent any excessive movement of the isolation packer during the high-pressure fracturing operation, Fig. 8. In spite of all the aforementioned efforts, communication between stages was still observed. Several other attempts were made to reduce the communication impact, such as the use of double packers and the elimination of flow back operations between stages to avoid the suction effect, but the communication issue was still not completely resolved. Only one strategy has effectively resolved the communication issue: changing the wellbore azimuth from the σmax to the minimum horizontal in situ stress plane (σmin).
Changing the Drilling Direction from σmax to σmin
Initially, MSF wells were drilled toward the σmax direction for better wellbore stability and a higher rate of penetration (ROP) for the drilling bit. Because MSF conducted in wells drilled in the direction of σmax results in longitudinal fractures that often have some form of hydraulic communication between zones of the first fracture stage and zones of the subsequent fracture stages, the decision was made to change the wellbore azimuth of MSF wells to the σmin direction, resulting in transverse fractures and helping to reduce the communication issue between the completion stages, Fig. 9. This change was very challenging from a drilling viewpoint as it required much more planning and time. Before a well could be drilled, the geomechanics of the area around the planned well had to be studied to mitigate the wellbore stability issues caused by the high horizontal stresses imposed on the wellbore when drilling perpendicular to the natural fractures in the formation. Also, to improve the ROP while drilling in the σmin direction, heavy-duty bits developed for very high revolution-per-minute applications had to be used.
The following are examples of a carbonate well drilled in the σmax direction where no communication between stages was observed. Second, a carbonate well drilled in the σmax direction where communication between stages was observed. Third, a carbonate well drilled in the σmin direction where no communication was observed; and finally, a sandstone well drilled in the σmin direction where no communication was observed.
EXAMPLE WELL H-9 (CARBONATE WELL DRILLED IN σMAX WHERE NO COMMUNICATION WAS OBSERVED)
Well H-9 was drilled in the carbonate Khuff-C formation towards the σmax direction. This led to the expectation of longitudinally oriented fractures, i.e., fractures primarily aligned along the wellbore. Subsequently, the well was completed with a three-stage MSF system, Fig. 10.
During the fracturing operation, the first frac port opened at 5,565 psi after pumping 6 barrels (bbl) of treated water. Then the first stage was successfully acid fractured, Fig. 11. The step rate test and step down test (SRT/SDT) for the second stage confirmed that there was no communication with the first stage, Fig. 12. Subsequently, the second stage was successfully acid fractured, Fig. 13. Afterwards, a SRT/SDT was conducted for the third stage, and it confirmed that there was no communication, Fig. 14. Subsequently, the third stage was successfully acid fractured, Fig. 15. After treating the entire interval, the well achieved a stabilized flow rate of 21.1 million standard cubic ft per day (MMscfd) at a flowing wellhead pressure (FWHP) of 2,150 psi. It is noteworthy to mention here that for all of the stages no flow back operations were conducted before fracturing all stages to avoid any suction effects that could lead to hydraulic communication between stages.
EXAMPLE WELL U-1 (CARBONATE WELL DRILLED IN σMAX WHERE COMMUNICATION WAS OBSERVED)
Well U-1 was sidetracked as highly slanted in the σmax direction with a net reservoir contact of 1,557 ft, Fig. 16. The well was completed with MSF equipment in the carbonate Khuff-B formation, Fig. 17.
With the MSF system deployed at the target depth, the first port was opened. The first stage was then successfully acid fractured by pumping a mixture of pad, acid and diversion fluid. Subsequently, during the main treatment of the first stage, there was a drop of about 5,254 psi surface pressure, from 16,054 psi to 10,800 psi, Fig. 18. When pumping commenced in stage 2, it was very clear that there was communication between stages 1 and 2. As shown in Fig. 19, an immediate pressure decline to 0 psi surface pressure (treating pressure) occurred within seconds when pumping was stopped. In a new formation that is tight and unstimulated, the pressure should bleed off gently and slowly; however, since stage 1 had been flowed back immediately after being acid fractured, it was likely that the zone was heavily drawn down, resulting in communication around the packers. Additionally, drilling the well in σmax direction means that MSF promotes longitudinal fractures that tend to propagate parallel to the borehole, thereby connecting the interval stages through the rock matrix. Accordingly, stages 2 and 3 were matrix acidized.
Table 1 shows the production rates from stage 1 (acid frac), stages 1 and 2 combined (stage 2 was matrix acidized), and the three stages combined (stage 3 was matrix acidized). In spite of the success in achieving a final stabilized rate of 18.7 MMscfd, the full advantage of the MSF system was not utilized as stages 2 and 3 were matrix acidized rather than acid fractured. This triggered the need to drill in the σmin direction to achieve full isolation between stages by promoting transverse fractures and minimizing longitudinal fractures.
EXAMPLE WELL W-1 (CARBONATE WELL DRILLED IN σMIN WHERE NO COMMUNICATION WAS OBSERVED)
Well W-1 was drilled in the σmin direction and completed across the carbonate Khuff-B formation using a two-stage MSF system placed over 1,477 ft of the horizontal lateral. The use of the MEM in real time optimized the challenging drilling operation along the σmin direction (perpendicular to the formation’s natural fractures). While executing the fracturing operation, the pressure signatures indicated the creation of separate fractures in each stage, Figs. 20 to 22. Currently, the well is producing at a rate of 35 MMscfd at 3,000 psi FWHP.
EXAMPLE WELL H-1 (SANDSTONE WELL DRILLED IN σMIN WHERE NO COMMUNICATION WAS OBSERVED)
Well H-1 was sidetracked, placing a 2,200 ft lateral drilled in the σmin direction across the sandstone Unayzah-A formation, and completed with a four-stage MSF assembly, Fig. 23. After the completion was set at the target depth, the four stages were independently proppant fractured using a total of about 680,000 pounds of proppant pumped in the four stages, Figs. 24 and 25, and Table 2. Figures 26 and 27 show the nodal analysis plot and post-job deliverability test for Well H-1, respectively. Also, Fig. 28 shows a 3D microseismic image (fracture mapping) exhibiting multiple fractures along the open hole lateral without any communication between stages.
STRATEGIES FOR SUCCESSFUL CT BALL SEAT MILLING OUT OPERATIONS
MSF technologies are meant to be interventionless, but coiled tubing (CT) interventions were made in four MSF wells in Saudi Arabia to mill out ball seats for different objectives, such as the cleanup of debris (e.g., excess proppant) and the opening of the frac port (if the port did not open after several attempts without milling) (8, 10, 11). Based on these CT intervention experiences, the following strategies were established to increase the success rate for the secondary (contingency) CT ball seat milling out operations.
The best scheme for a successful CT ball seat milling out operation takes into consideration both the ball seat material and the CT bottom-hole assembly. The ball seat should be readily millable in a relatively short time, and the milling tool should be aggressive enough to drill through the ball seat without damaging the MSF completion.
Weight-on-bit (WOB) proved a critical parameter in ball seat milling out jobs. Therefore, a CT force simulation should be run to check that sufficient WOB is applied in planning for the job. The optimum WOB was found to be in the range of 800 lb to 1,000 lb. If too little weight is applied, there will be no progress, but at the same time, if too much weight is applied, the mill may stall, Fig. 29.
PRODUCTION RESULTS AND DISCUSSION
MSF technologies have been successfully utilized in several gas fields in the Southern Area of Saudi Arabia covering both the carbonate Khuff and the sandstone pre-Khuff (mainly Unayzah) reservoirs, Fig. 30.
In general, the production results from wells completed using MSF technologies — as deployed in the Southern Area gas fields — have been very positive with actual results exceeding expectations. Figure 31 shows a comparison of the average well productivity of MSF wells with that of wells completed using other techniques (non-MSF wells) in the two main fields of the technology application, namely Field-A and Field-B. The comparison shows that significant production improvement was gained using MSF technologies in both fields. In Field-A, MSF wells produce at a rate that is approximately three times the rate produced by non-MSF wells, whereas in Field-B, MSF wells produce at a rate approximately 2.3 times the rate produced by non-MSF wells. While it is true that the reservoir properties are different from one well to the other in both fields and that most of the non-MSF wells are older, this production comparison indicates that MSF technologies enable very good well productivity with very competitive advantages. Accordingly, the forecast is that the application of MSF technologies will grow sharply and rapidly, especially as our industry moves into more development projects targeting unconventional resources.
In addition, Fig. 32 is a comparison between the average gas production rate for wells completed with MSF technologies and for offset wells completed with other horizontal open hole or cased hole completion techniques (H non-MSF wells) in the two main fields of application.
CONCLUSIONS AND RECOMMENDATIONS
1. Implementation of strategic mitigation practices has practically eliminated any deployment issues associated with MSF technologies and resulted in consistent successful deployment of the technologies to their target depth.
2. Proper use of the MEM has improved wellbore stability by providing the optimum mud weight when drilling in the σmin direction.
3. Multiple transverse fractures are required to maximize the contact area between the well and the formation, and to reap the full benefits of MSF technologies.
4. In general, carbonate wells drilled in the σmax direction with longitudinal fractures following MSF achieved good production results. But wells drilled in the σmin direction created multiple transverse fractures with MSF and resulted in a relatively higher production rate.
5. Changing the horizontal wellbore drilling direction from the σmax to σmin has helped significantly in minimizing hydraulic communication between the fracture stages in carbonate formations. Accordingly, it is recommended that wells planned to be completed with MSF technologies should be drilled in the σmin direction, except in cases where it is not viable, such as due to well proximity issues. In this situation, efficient matrix acidizing should be sought as an alternative.
6. A balanced system and anchoring tools are recommended to prevent any excessive movement of the isolation packers during the high-pressure fracturing operation.
7. The millability of the MSF system should be considered and evaluated if it seems likely that a CT ball seat milling out operation will be required during the life of the well.
8. Overall, the performance of wells completed with MSF technologies surpasses that of wells completed with other completion techniques, such as horizontal open hole and cased hole, in terms of stabilized gas production rate.
9. Based on the positive production results achieved from wells completed with MSF technologies, it is recommended to continue using MSF technologies in exploiting moderate and low permeability rock formations in the Kingdom.
The authors would like to thank the management of Saudi Aramco for their permission to publish this article. The authors would also like to thank the Southern Area Production Engineering Department and the Southern Area Well Completion Operations Department for their great support during the jobs’ design and execution. Additionally, a special thank you goes to the multistage fracturing team at Saudi Aramco, Wael El-Mofty from Packers Plus and Stuart Wilson from Schlumberger.
This article was presented at the SPE Saudi Arabia Section Annual Technical Symposium and Exhibition, al-Khobar, Saudi Arabia, May 19-22, 2013.
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