INTELLIGENT WELL COMPLETION

MRC as intelligent completion functions with multiphase flow monitoring

 Results from a Saudi Aramco well indicate that a maximum reservoir contact well with IWS’s that include multiphase flow measurement from each lateral can succeed with minimal incremental risk, compared to a conventional completion. 

Fahad AI-Bani, Hassan AI-Sarrani and Ibrahim Arnaout, Saudi Aramco; Adam Anderson and Yaser Aubed, Baker Oil Tools; and E. S. Johansen, Weatherford International

In today’s drive to improve well production, more innovative methods are continually being implemented to enhance well productivity and reservoir management. Remote monitoring and interactive control are two such methods that are frequently employed to derive more value from wells. In Saudi Arabia, the world’s first Maximum Reservoir Contact (MRC) well to use Intelligent Well Systems (IWS) and fiber-optic monitoring to maximize production performance was implemented.

Remote monitoring and interactive control systems were implemented on Well 194, which was drilled as a tri-lateral MRC well with 4.2 km (2.61 mi) of total reservoir contact. The IWS utilized feed-through production packers to isolate each of three laterals in the motherbore. Three remotely operated downhole chokes were installed to independently control flow from each lateral to optimize overall well production. This control extends the production plateau while maximizing reservoir drainage.

The fiber-optic monitoring system enables remote monitoring of key production parameters, including pressure, temperature, total flowrate and water cut from each of the laterals, used to determine optimum downhole choke settings. Finally, the well was implemented as “ESP-ready” with 7-in. tubing and a deep-set SCSSV to enable subsequent installation of a thru-tubing ESP to further improve production.

Ultimately, this configuration resulted in a well capable of producing at a very high rate with low drawdown for an extended period of time. This strategy will result in a long-term sustained rate while optimizing the reservoir drainage process. This article reviews the lessons learned and key issues related to implementing this type of “next generation” well completion system.

MRC WELL OVERVIEW

The definition and benefits of MRC wells have been well defined.¹ However, for the purpose of this article, a short description and application of this technology is important.

In lower permeability carbonate facies environments, significantly extending the wellbore reservoir contact will yield significant enhancements in the well’s Productivity Index (PI). The length that a single horizontal lateral can be drilled is limited by drilling constraints, such as torque and drag, as well as productivity issues around flowing back, cleaning up, and getting significant production from excessively long horizontal wells. Multi-lateral technology has been utilized to extend reservoir contact while not exceeding drilling and production constraints.

Typically, an MRC well consists of three or four single openhole laterals drilled from one motherbore. Naturally, each single lateral acts as a single well with variances in permeability and productivity identified from lateral to lateral. An IWS can be installed in the motherbore of an MRC well to mitigate the risk associated from variances in reservoir parameters that can lead to early water breakthrough and poor ultimate recovery.

In the case of Well 194, the IWS consisted of three separate downhole valves and monitoring stations. They independently monitor the production rate and water cut from each lateral, and then enable remote isolation of each lateral without intervention, Fig. 1.

Fig. 1. Well 194 MRC well diagram.

INTELLIGENT WELL SYSTEM TECHNOLOGY

Different definitions of IWSs have been presented in the past. For the purpose of this article, an IWS is defined as a completion system that enables remote (or interventionless) control and monitoring of multiple zones within a single well, for the purpose of optimizing production, improving reservoir management and reducing intervention cost.

The original envisaged application for IWS was as a specialty completion system to reduce the number of interventions required in deepwater, subsea, extended reach or other high-intervention-cost wells. In a deepwater subsea well, the intervention cost to isolate a given zone can easily exceed $10 million. Justifying the use of IWS technology to eliminate this intervention expense is a relatively straightforward process.

As the technology has progressed, there has been a much broader application of IWS. Increasingly, IWS is used as a technique to better manage reservoir drainage and wellbore performance. In the case of Well 194, the IWS enables the maximum amount of reserves to be recovered from the wellbore. In an MRC well, if one lateral waters out prematurely, then the entire well can be lost. However, the IWS enables the optimization of the MRC well, and water production can be choked back or isolated altogether. This functionality can significantly extend the well’s life and the total oil recovered from it. A diagram of the completion system installed in Well 194 is shown in Fig. 1, with each of the key system components highlighted.

Production from each lateral first enters the mainbore. The production packer isolates each lateral and then forces the produced fluid from each lateral into the downhole choke.

The cornerstone of the IWS is the downhole, hydraulically operated choke. In the case of Well 194, the downhole choke has eight positions�100% open, 20% open, 15% open, 12% open, 9% open, 6% open, 3% open and 0% open. The choke position is controlled with a hydraulic actuator that has two hydraulic lines from the downhole choke back to surface. To move the downhole choke from one position to the next, pressure is cycled on the hydraulic control lines. The downhole choke’s position is verified to measure the amount of fluid returned from each successive valve operation. A diagram of this choke is presented in
Fig. 2 for reference.

Fig. 2. The downhole, hydraulically operated choke has eight operating positions.

FIBER OPTIC MONITORING SYSTEM

Optical sensing systems are designed with the philosophy of having low complexity and passive components downhole while keeping active electronic equipment on the surface to ensure high reliability and measurement accuracy.

The optical pressure and temperature (P/T) gauges deployed in Well 194 are Fiber Bragg Gratings-based (FBG) sensors that have demonstrated excellent long-term field performance (more that 160 gauges installed worldwide). The gauges provide real-time zonal (P/T) for production monitoring and well diagnostics.

Downhole optical two-phase flowmeters were also deployed in Well 194. These represent a leap in technology² and enable real-time allocation of production in multi-zone and multi-lateral completions.³ The optical flowmeter is full-bore, with no intrusions and no exposed sensors, allowing full through-bore access. The full-bore design also means no permanent pressure loss and excellent resilience to erosion. Furthermore, the flowmeter is interrogated by the surface-mounted instrumentation, and it contains no downhole electronics or moving parts, and has no nuclear sources, thus ensuring excellent long-term reliability The meter’s robustness also allows for performing workover, perforating and hydraulic fracturing operations with the flowmeter in place.

The downhole flowmeter makes two primary measurements: bulk averaged flow velocity and bulk speed of sound. Flow velocity is directly proportional to the total volumetric flowrate, and the speed of sound is directly proportional to the watercut. Speed of sound vs. watercut is shown in Fig. 3, where a measured speed of sound of 1,200 m/sec yields a watercut of 18%.

Fig. 3. Speed of sound vs. water cut in Well 194.

The optical flowmeter has demonstrated measurement accuracy in single-phase liquids and gases to ±1%. In two-phase oil-water mixtures (when operating above bubble point, such as for Well 194), the flowrate and water fraction accuracies have been demonstrated to be within ±5% over the full range of watercuts.

In Well 194, three flowmeters are deployed to measure the flow contribution from each of the three producing zones, Fig. 1. The lowest flowmeter directly measures the production from the lowest zone. The middle flowmeter measures the combined flowrate from the middle and lower zones. The middle zone production is, therefore, the difference in flowrate measured by the middle and lower flowmeters. Similarly, the upper flowmeter measures the combined flowrate from all three zones. The upper zone production rate is, therefore, the difference between the upper and middle flowmeters. The flow measurement system includes embedded PVT, and it reports flowrates and both downhole and standard conditions.

The combination of real-time pressure and temperature, and oil and water flowrates, from each of the three producing zones enables a new level of reservoir management and optimization not possible with conventional systems. Increasing zonal water production can be addressed immediately by choking back output from the problem zone with the downhole flow control valve.

WELL CONSTRUCTION AND SYSTEM INSTALLATION

A brief overview of the well construction process is included below. This section’s primary focus will be from Step 10 to Step 18, reviewing the processes around installing the IWS.

Well 194’s construction was as follows:

1. Drill out 8½-in. open hole to about 11,310 ft at 90° inclination

2. Run and cement 7-in., 26 lb/ft liner from 6,470 ft to 11,300 ft

3. Drill out 7-in. liner shoe and drill ahead 6 1/8-in. open hole to TD of about 14,300 ft

4. Set whipstock and sidetrack out of 7-in. liner for first lateral�window depth from 9,190 to 9,200 ft

5. Drill 6 1/8-in. open hole to TD of about 13,200 ft

6. POOH drilling assembly and RIH with whipstock-retrieving tool, and retrieve whipstock

7. Set whipstock and sidetrack out of 7-in. liner for second lateral-window depth from 7,160 to 7,170 ft

8. Drill 6 1/8-in. open hole to TD of about 11,200 ft

9. POOH drilling assembly and RIH with whipstock-retrieving tool and retrieve whipstock

10. Clean up wellbore with cleanout assembly (five trips were made with brushes and magnets)

11. RIH with IWS and fiber optic monitoring system

12. Run 7-in. production tubing back to surface

13. Make up tubing hanger and run control lines through tubing hanger

14. Land tubing hanger

15. Function-test all downhole valves and measure P/T profile

16. Close all downhole chokes

17. Pressure up to 4,200 psi to set packers

18. Test backside to 1,500 psi to test packers

19. Well ready for flowback and production.

After retrieving the final whipstock (Step 9 above), the well was prepared for installation of the IWS. One of the critical concerns of running an IWS completion in an MRC well is properly cleaning up the motherbore to remove any debris associated with milling the windows and drilling the lateral sections. Well 194 proved to be quite littered with debris from this process, and five cleanup trips were made with scrapers, brushes and magnets. On the fifth trip, it was determined that the debris had reached an acceptable level and that the well would not significantly benefit from additional cleanout trips. The debris pulled from the first cleanout trip is shown in Fig. 4.

Fig.4. Debris pulled from Well 194 during the first cleanout trip.

After the final cleanout trip, the completion tubing-running equipment was set up for running 3½-in., 4½-in. and 7-in. production tubing. The torque turn equipment was specially prepared to have a slot in the bowl, to allow the control lines to be bypassed between the slips and bowl during tubing running. While the tubing make-up equipment was prepared, the spool of control lines for operating the IWS equipment was run through shieves that were then hung from the monkey board. Since the production tubing is run in-hole, the control line is reeled off the control line spool and through the shieve, and is then clamped to the tubing string. Figures 5 and 6 illustrate the control line spooling units and how they were set up on the rig.

Fig. 5. Spooling unit with hydraulic flatpack.

Fig. 6. Spooling unit arrangement on rig.

A significant amount of rig time is required to make up, test and ultimately install an IWS. The most important thing is to focus on the well’s long-term reliability, as opposed to saving a few hours of rig time. Therefore, there was a focus on ensuring flawless system execution rather then speeding through the process to save a few hours of rig time.

After the tubing-running tools are prepared, the make-up and running of the individual completion components can begin. To minimize the number of hydraulic and fiber optic connections that must be made up on location, the completion components were made up into sub-assemblies that were easy to handle with pre-made hydraulic and fiber optic splices. Twelve separate assemblies were required, each with various purposes. These assemblies were picked up, made up and tested in succession as follows:

1. Assembly 1�Bull plug and tubing joint-prevent flow from the mother bore into the tubing string without passing through the downhole choke in Assembly 2.

2. Assembly 2 �Downhole choke and packer for the motherbore. This isolates the motherbore from the upper laterals and controls its flow through the downhole choke, which can be used to regulate or shut off the mainbore. The downhole choke was fully functional, once it was brought to the rig floor before running in-hole to ensure proper operation.

3. Assembly 3�Multiphase flow meter assembly, which consists of a P/T gauge, as well as the flowmeter. This assembly monitors tubing pressure and the motherbore total rate and water cut.

4. Assembly 4�Blast joint assembly is positioned across the first window, and utilized to protect the flatpack and tubing string from erosion as a result of high-velocity flow.

5. Assembly 5�Downhole choke and packer for Lateral 1.

6. Assembly 6�Fiber optic P/T and multiphase flowmeter for Lateral 1.

7. Assembly 7�Crossover from 3½-in. to 4½-in. production tubing.

8. Assembly 8�Blast joints for protecting tubing string and control line across Window 2.

9. Assembly 9�Downhole choke and packer for Lateral 2.

10. Assembly 10�Fiber optic P/T and multiphase flowmeter for Lateral 2.

11. Assembly 11�Mechanical sliding sleeve to displace well to diesel.

12. Assembly 12�Tubing retrievable surface-controlled sub-surface safety valve to facilitate through-tubing ESP installation.

Between each of the assemblies, 3½-in. and 4½-in. production tubing joints were made up. The hydraulic and fiber optic lines were run along the production tubing and clamped to the tubing at each coupling. To minimize the fiber optic splices required on location, pre-made lengths of fiber optic line were made up, to run from each fiber optic assembly to the next successive assembly. This process both reduces rig time and improves reliability, because no fiber optic connections are made up on location. Rather, they are made up in a clean, well-confined environment in the shop prior to installation. Additionally, the downhole choke assemblies were pre-plumbed, with the hydraulic control lines made up and pre-installed through the packer body. As a result of this pre-job preparation, a significant amount of rig time was saved, and a minimum number of connections were required to be made up on the rig floor. This ultimately enhances the reliability of the system’s operation.

The installation of each assembly went smoothly; however, some non-productive time was experienced as a result of the fiber optic line being damaged after the slips were set on it. Even though there should have been enough space to allow clearance of the fiber optic line between the slips and bowl, an accident occurred, and the line was damaged. The line was fusion-spliced (in a specialized workshop container) on location, and corrective action was implemented on the rig floor to minimize the risk of such problems during the rest of the completion installation operation.

After each of the individual assemblies were made up and tested, 7-in. production tubing was run from the uppermost assembly to surface. After all production tubing was made up, the tubing hanger was made up with a pre-installed landing joint on top. Each control line was individually fed through the tubing hanger and tested. After propping the tubing hanger, the completion was landed and the hanger set in the tubing spool.

After landing the hanger, all of the downhole chokes were functioned through all positions to ensure proper operation of the valves; to verify system integrity, all fiber optic gauges were tested. This process, although consuming roughly 6 hr of rig time, was critical to assuring that all systems were properly functioning prior to passing the point of no return. Tubing pressure was then applied to set each of the three production packers in the tubing string. After setting all packers, annulus pressure of 1,500 psi was applied to test the packer integrity.

At this point, downhole completion components were verified to be functioning properly, and the well was ready to be prepared for production. A back pressure valve was installed in the tubing hanger to allow the BOPs to be nippled down, and the bonnet and Christmas tree were made up. After making up the tree, coiled tubing was rigged up and run in to shift the mechanical sliding sleeve open. After sliding the sleeve open, the well was displaced to inhibited diesel. This lightens the tubing fluid to allow the well to flow, and protects the annulus and tubing string from corrosion. After displacing the well to diesel, a final coiled tubing trip was made to close the sliding sleeve. At this point, the well was ready to be flowed back.

WELL 194 PRODUCTION

At the time this article was written, the well was producing with all three laterals opened 100%. Initial production results were quite promising. After the surface control systems for the fiber optic and IWSs were installed, each lateral would be individually tested to verify flowmeter performance and the productivity index. This information would enable production engineers to adequately determine the optimum choke setting from each lateral to maximize reservoir recovery efficiency from each lateral.

One of this completion system’s unique features is the Tubing-Retrievable Sub-Surface Safety Valve and 7-in. tubing that were installed to facilitate the installation of a thru-tubing ESP. In this area of the field, lower reservoir pressure and a small increase in water production from one lateral will lead to the well being unable to flow naturally after a period of time. Rather than pulling the entire completion, an ESP can be run through tubing, with the safety valve used as a downhole barrier to enable the ESP to be run on coiled tubing without killing the well. This process will enable significantly more reserves to be recovered from the well without the significant cost associated with a conventional well workover.

CONCLUSIONS

The results from Well 194 indicate that an MRC well with IWSs that include multi-phase flow measurement from each lateral can be successfully installed, with a minimum amount of incremental risk, compared to a conventional completion. Key lessons learned from the installation of this system are:

• Minimize the number of control line and fiber optic connections required at the rig site by pre-plumbing sub-assemblies as much as possible
• Pre-measure the tubing joints between each assembly to ensure the fiber optic line lengths accurately match the tubing lengths between each zone
• Blast joints can be utilized to protect both the control lines and tubing string from high velocity through the lateral windows.

In addition, proper pre-job planning and consideration of the tubing running equipment will minimize risk associated with damaging control lines while running tubing. Fiber optics and IWS’s can be successfully integrated to provide enhanced reservoir monitoring and control capability.  

ACKNOWLEDGEMENTS

The authors would like to thank management at Saudi Aramco, Baker Oil Tools and Weatherford for their permission to publish this article.

REFERENCES

¹   N. G. Saleri, S. P. Salamy, H. K. Mubarak, R. K. Sadler, A. S. Dossary and A. J. Muraikhi, “A maximum reservoir contact (MRC) well and its implications for developing tight facies reservoirs,” SPE paper 88986, August 2004.
²   T. K. Kragas, F. X. Bostick, C. Mayeu, D. L. Gysling and A. M. van der Spek, “Downhole fiber-optic multiphase flowmeter: Design, operating principle, and testing, SPE paper 77655, presented at the SPE Annual Technical Conference and Exhibition, San Antonio, Texas, Sept. 29-Oct. 2, 2002.
³   B. Sandey, et al, “Improved reservoir management with intelligent multi-zone WAG injectors and downhole optical flow monitoring, SPE paper 95843, presented at the SPE Annual Technical Conference and Exhibition, Dallas, Oct. 9-12, 2005.

This paper was prepared for presentation at the 15th SPE Middle East Oil & Gas Show and Conference, Bahrain International Exhibition Centre, Kingdom of Bahrain, March 11-14, 2007.