New-Generation Drillstring Safety Valves
- B.A. Tarr (Mobil) | R. Luy (ITE Engineering GmbH) | G. Rabby (Hi-Kalibre Equipment Ltd.) | H. Kickermann (DAGGER) | J. Senftleben (Intl. Tiefbohr GmbH & Co. KG) | J. Cunningham (M&M Intl. Inc.)
- Document ID
- Society of Petroleum Engineers
- SPE Drilling & Completion
- Publication Date
- September 2003
- Document Type
- Journal Paper
- 256 - 266
- 2003. Society of Petroleum Engineers
- 1.11 Drilling Fluids and Materials, 1.7.5 Well Control, 2.1.7 Deepwater Completions Design, 5.4.2 Gas Injection Methods, 1.6.1 Drilling Operation Management, 1.6 Drilling Operations, 1.7 Pressure Management, 1.10 Drilling Equipment, 1.10.1 Drill string components and drilling tools (tubulars, jars, subs, stabilisers, reamers, etc), 2 Well Completion, 2.4.3 Sand/Solids Control, 5.3.2 Multiphase Flow
- 3 in the last 30 days
- 309 since 2007
- Show more detail
- View rights & permissions
|SPE Member Price:||USD 5.00|
|SPE Non-Member Price:||USD 35.00|
Drillstring safety valves (DSSVs) are considered an essential part of the well-control equipment on every rig, but performance problems in stripping operations motivated one operator to lead an industry effort to develop appropriate functional specifications for consideration by API and to conduct the associated performance testing described in this paper. Results of testing three different valves indicate that common DSSV performance problems can be addressed and that the proposed new performance specifications for a new generation of DSSVs are generally workable.
API subsequently incorporated many of the proposed changes into the 40th edition of API Spec. 7, identifying the new-generation valves as Class 2 valves suitable for surface and downhole (stripping) service.
DSSVs, including kelly valves (whether used with a kelly or with an overhead drilling system), full-bore stabbing valves, and inside blowout preventer (BOP) type check valves, are routinely used in drilling operations as part of the well-control equipment. However, DSSVs were addressed only in a very limited fashion in previous API specifications. The 38th edition of API Spec. 7, Section 2, "Upper and Lower Kelly Valves,"1 essentially addressed only pressure-containment requirements for kelly valves that remain above the BOP. For tension limits at the rated working pressure, temperature range for sealing, ability to close on backflow, operating-torque characteristics, and fluid-compatibility information, operators had to rely on the manufacturer's published data.
At the time this work was undertaken, no industry specifications existed for DSSVs that could be used for stripping into a live well below the BOPs, as required when a kick is taken during tripping. For stripping applications, the stem seal of a DSSV must hold pressure from the outside because a slug of lower-density influx fluid in the annulus, the kick, results in a higher annulus pressure at the surface.
This investigation into problems associated with DSSVs began in 1993 after several incidents were reported of stabbing valves leaking downhole when stripped into wells under pressure. API-certified manufacturers of kelly valves were asked if they could supply engineering data to verify the suitability of their products for service conditions beyond the kelly valve requirements of API Spec. 7, Section 2. The results confirmed the need for improved specifications, particularly for full-bore stabbing valves.
In 1994, a survey of operators' experiences with DSSVs confirmed that there was a general industry need for an improved valve design to address the limitations of current designs, and DSSV manufacturers were invited to submit designs for a new-generation DSSV. One operator, Mobil, also approached API and obtained approval to form a DSSV task group to address the shortcomings of the kelly valve specifications in Section 2 of API Spec. 7. The DSSV task group was set up to report to the Drill Stem Components & Compounds Sub-Committee of the API Drilling Standards Committee.
In 1995, after the API task group developed the first draft of a new specification, a corresponding DSSV testing program was proposed as a joint industry project (JIP), and the Gas Research Inst. (GRI) agreed to be the major sponsor. Three manufacturers agreed to supply valves for the testing program. Results from the testing program are discussed in this paper.
Identification of the Problem
After experiencing some leak problems through the stem seals of ball-type DSSVs that were stripped into a well under pressure, a review of DSSVs was initiated in 1993. The review was to establish the design capabilities of valves made by different manufacturers and to establish whether the leak problem experienced was unique to one manufacturer or a more general problem. The results indicated that the majority of manufacturers were unaware of the design requirements for ball-type DSSVs used in well-control operations involving stripping because API specifications did not address the requirement to hold pressure across the stem seal from the outside.
In March 1994, as a follow-up to the review of manufacturers, a DSSV failure-frequency questionnaire was sent out by Mobil to a number of other operators. The results are presented in Table 1, in which the number of Xs indicates the relative frequency of the specific failure types experienced. Based on the common problems listed in Table 1, it was apparent that some were inherent to the basic design of typical valves and that some occurred simply because they were not addressed in relevant specifications.
A typical DSSV has a floating ball that is turned by a single crank through a tongue-and-groove connection, as shown in Fig. 1. The historical problems associated with many floating-ball- type DSSVs can be explained as problems either inherent in current designs or resulting from not being addressed in any of the 1994 specifications.
DSSV Design Problems
Inability to close on flow because of high torque. High torque results from several sources because the flow is throttled by the closing ball, including binding from misalignment of the ball and operating stem and high ball-to-seat contact friction force.
Inability to open with high, near-equalized pressure. High torque results from the large end-load pressure force acting on the very small thrust-bearing surface of the stem.
Limitations in the 1994 Industry Specifications for DSSVs
No requirement to hold the fluid pressure applied to the closed valve from above.
No requirement to hold the fluid pressure applied to the outside of the valve-operating stem seal(s).
No verified operating temperature range for sealing.
No requirement to seal against gas.
No required reporting of the valve's body-material yield limits under combined pressure, tension, bending, and torque.
No verified operability of the valve in a mud environment.
No verified tension range for effectively sealing stem seals with internal or external pressure.
|File Size||2 MB||Number of Pages||11|