Simple smart well approach
BJ Services Co.
Initial intelligent well completions focused on the ability to remotely control reservoir access from surface facilities. The idea was to access multiple reservoirs and exploit reserves without expensive workover operations. As this technique began to evolve, additional aspects of the completion process began to emerge that were not addressed using conventional completion techniques.
Based on these issues, objectives were defined for a next generation intelligent well completion system that would integrate all aspects of the completion, from sand control through placing the well on production.
PACV technology was utilized successfully in previous applications where upper zone isolation was required and mechanical intervention was not possible with the production string in place.
Primary objectives with their benefits for the next generation intelligent well completion were:
- Maintain fluid loss and well control at all times prior to the initiation of production
- Require no mechanical post completion intervention
- Use simple reliable technologies, such as independent hydraulic flow control mechanisms, simple pressure actuated fluid loss devices, and redundant capabilities for backup operations
- Maximize production potential by maintaining large bore flow areas and minimize formation damage.
These objectives were systematically applied to completion operations beginning with the lower zone sand control and ending by placing the well on production. The resulting developments form an integrated system that allows the entire completion to meet the outlined objectives.
Lower zone completion
In the past, lower zone completions used mechanical sleeves to gravel pack, isolate, and produce the reservoir. These sleeves were normally run concentrically inside the lower zone screen assembly and mechanically manipulated after the gravel pack was complete. It was necessary to use slickline or coiled tubing to reopen the sleeves for production. This system met the necessary criteria for fluid loss and zone control. It was, however, not totally intervention-less.
The intervention-less solution to this problem was a derivative of systems originally developed for the upper zone. These systems included a pressure actuated circulating valve (PACV) that is combined with a similar device known as an annular flow valve (AFV). PACV technology was used successfully in previous applications where upper zone isolation was required and mechanical intervention was not possible with the production string in place. The valve is run in the closed position and actuated with differential pressure from the tubing to the annulus. Once open, it allowed flow from the outer annulus through flow ports into the tubing inside diameter (ID). It could be run as base pipe under the screen or included in a concentric string across the producing interval.
The annular flow valve was designed to utilize and control a different flow path. In the run-in position, it effectively blocks off flow from the concentric area below the valve to the concentric area above the valve. In the most common applications, it is run between the packer and blank/screen assembly in the upper zone flow path, effectively eliminating flow when closed.
Application of a pre-set differential pressure will shift an internal piston, which opens a bypass that allows flow from the concentric area below the valve to the concentric area above the valve. The AFV has a mechanical backup, which can be accessed down the long string to mechanically shift the valve if required.
The valve design is such that it is balanced until the production seals are landed in order to prevent inadvertent actuation. Both the PACV and AFV devices were considered viable alternatives for the upper zone completion while meeting all of the proposed design objectives.
The challenge in utilizing either of these technologies on the lower zone was the inability to prevent upper zone treating pressures from actuating the lower zone fluid loss device(s). Installing both an AFV and PACV in tandem presented a unique solution to this problem. The valves were aligned such that the upper zone treating pressure was routed into both the ID of the lower zone and into an artificially created concentric space above the lower zone annular flow valve. During the gravel pack and frac pack treatment, pressure is balanced across the valves which eliminates any chance of them opening prematurely. Hence, this solution was chosen as the primary design for the intervention-less lower zone completion.
As described previously, both the PACV and AFV were viable alternatives for intervention-less upper zone completions. The AFV was selected based on flow parameters and well economics. Utilization of these devices would provide positive zonal isolation of each zone after gravel pack operations and would remain isolated until the well was ready for production operations to begin. At this point, both zones can be selectively or simultaneously opened by applying pressure down the tubing to create the required opening differential of the valves.
To meet the required flow control objective, available systems were analyzed for simplicity, reliability, fit, and functionality. These included electric, electro-hydraulic, and straight hydraulic. To meet the simplified technology standard as set out in the original objectives, a straight hydraulic control system was chosen that incorporated two independent axial-type-sliding sleeves.
A three-line control system was selected using one independent control line to open each of the sleeves and a common close line. This approach allows for complete and individual operation of each valve assembly. Valve position indication is based on pressure response and volume measurement.
The valves were developed utilizing existing technology found in current mechanical sleeves that include non-elastomeric seals and a proprietary equalizing system. The hydraulic downhole flow control valve system (DFCS) was extensively tested and certified to 10,000 psi differential under static conditions and 2,500 psi differential under cyclic conditions.
To complete the intervention-less intelligent well, additional components were required that included the production packer, jet sub, and control line connector sub.
The multiple pass-through production (MPTP) packer is run with the production tubing and can be retrieved with straight over-pull. Its design has accommodations for multiple pass throughs. The initial system was developed for 7 in. casing and maintained a 2 7/8 in. equivalent ID flow area with four allowable 1/4 in. pass-throughs. Next, the 9 5/8 in. version was developed with mandrel flow areas equivalent to 3 1/2 in., 4 in., and 4 1/2 in. tubing while maintaining a minimum of six pass-through bores on all sizes. The design was gas tested to 10,000 psi differential at 250° F temperature.
The jet sub is a short pup joint designed to be run above the packer to allow cutting of both the tubing and the control lines without leaving pieces of unsecured control line. The control line connector sub terminates all control lines attached to the hydraulic flow control valves to the flat packs that run to surface.
Case history A
The first field trial was conducted on a well with two productive intervals in excess of 12,000 ft measured depth and bottom hole pressures in excess of 8,000 psi utilizing 7-in. casing. The lower zone was completed with a high rate water pack utilizing a mechanically activated fluid loss control system for well and fluid loss control. The upper zone was a frac pack completion using a number of PACV pressure activated circulating valves spaced in the upper assembly. The valves are activated from surface with a pressure response and were designed for actuation in intervals with no mechanical avenue for manipulation.
The MPTP packer is run with the production tubing and can be retrieved with straight over-pull. Its design has accommodations for multiple pass throughs.
After completion of both zones, without incident, the hydraulic DFCS was installed in the well in preparation for production activities. The system tested and performed as designed exceeding all expectations.
Once the well was ready for production the schedule was to activate the lower mechanical fluid loss device with wireline and use pressure from the surface to activate the PACV on the upper zone. The production of the well would then be controlled with the upper and lower downhole flow control valves. Due to foreign debris in the system, however, wireline was unable to get to bottom and coiled tubing was required to clean out the wellbore.
At this point, the lower zone mechanical fluid loss system was actuated using slickline. In this initial design, slickline was also required to set the blanking plug below the upper flow control valve to isolate reservoir flow. The intelligent flow control valves were functioned to isolate the upper zone and the PACV system was actuated. Both zones were independently flow tested during this process and have been on production since July 2000 without incident.
The field trial confirmed the technology of the new, reliable, and economic intelligent well flow control system as a viable completion alternative. The system was proven and ready for additional wells and other casing configurations. The ultimate goal was to eliminate all risks associated with these types of completions while maintaining the primary objectives mentioned in the introduction. Consequently, it was obvious that a pressure actuated fluid loss system similar to the PACV was needed to eliminate the mechanical risk associated with the lower zone.
Case history B
This well was a two-zone completion in 9 5/8-in. casing with a measured depth and bottom hole pressure in excess of 12,000 ft and 7,000 psi respectively. Both zones were oil-producing reservoirs completed with high rate water pack treatments. The lower interval utilized an AFV/PACV combination for fluid loss and well control after treatment. An AFV with an extended seal bore was used in the upper interval to control the well and simplify the process of spacing out production seals and landing the hanger.
After completion of the lower zone, the workstring and associated sand control service equipment were removed from the well and the new annular flow valves successfully tested. The upper zone was treated without incident or failure of the lower zone pressure actuated fluid loss system. The AFV/PACV valves provided well control while installation of the downhole flow control valves were installed.
The system was successfully installed in the 9 5/8-in. casing above the upper gravel pack. The completion fluid was then replaced with a lighter packer fluid and the hanger landed and locked. After successful packer testing, downhole flow control valves were manipulated as necessary, and pressure from surface applied to actuate the fluid loss devices. Both zones were flowed successfully.
This well confirmed the design and testing of the new pressure actuated fluid loss device as well as proving out the 9 5/8 in. DFCS. Complete fluid loss and well control were maintained until the well was opened to flow.
Case history C
Another field trial was a two-zone well with 9 5/8 in. casing at approximately 10,000 ft measured depth and bottom hole pressures of around 5,000 psi. Both zones were completed with the new completely intervention-less fluid loss control system and DFCS.
The lower interval was completed with a high rate water pack and the upper interval utilized a frac pack completion. The AFV/PACV devices were successfully tested and the DFCS was installed. Pressure was applied as needed to actuate the fluid loss devices and open the well for production. The hydraulic sleeves were positioned as necessary and each interval successfully flow tested.
These case histories, along with others, prove that a complete and intervention-less intelligent completion system is a viable and economic completion alternative, including:
- A simple smart well approach that provides necessary functionality without extraneous features or unnecessary cost
- Downhole pressure gauges, SCSSVs, and chemical injection valves can all be installed at the same time with the smart well system. This saves the additional time required to install the smart well equipment, terminate the control lines, function test the valves and place the equipment into service, now estimated to be less than 24 hours of rig time
- The additional capital cost of the new smart well equipment is estimated to be only about 20% of the total completion equipment cost
The first field trial was conducted on a well with two productive intervals in excess of 12,000 ft measured depth and bottom hole pressures in excess of 8,000 psi using 7 in. casing.
- The system provides total positive zonal isolation of the producing reservoirs after each well is gravel packed
- The system eliminates all slickline and mechanical intervention work requirements below the tubing hanger during and after the completion
- The system provides a means to manually isolate (via slickline or coiled tubing) and produce each of the producing reservoirs if the smart well system malfunctions as a means of redundancy.
The authors wish to extend thanks to the management of BJ Services Co. and Kerr-McGee Corp. for their permission and support to publish this paper. They also thank those who contributed information, testing, and field support to make the project a success.