New-Generation Drillstring Safety ValvesB.A. Tarr,* SPE, Mobil; R. Luy,** SPE, ITE Engineering GmbH; G. Rabby, Hi-Kalibre Equipment Ltd.; H. Kickermann,

and J. Senftleben, Intl. Tiefbohr GmbH & Co. KG; and J. Cunningham, M&M Intl. Inc.

SummaryDrillstring safety valves (DSSVs) are considered an essential partof the well-control equipment on every rig, but performance prob-lems in stripping operations motivated one operator to lead anindustry effort to develop appropriate functional specifications forconsideration by API and to conduct the associated performancetesting described in this paper. Results of testing three differentvalves indicate that common DSSV performance problems can beaddressed and that the proposed new performance specificationsfor a new generation of DSSVs are generally workable.

API subsequently incorporated many of the proposed changesinto the 40th edition of API Spec. 7, identifying the new-generationvalves as Class 2 valves suitable for surface and downhole (strip-ping) service.

IntroductionDSSVs, including kelly valves (whether used with a kelly or withan overhead drilling system), full-bore stabbing valves, and insideblowout preventer (BOP) type check valves, are routinely used indrilling operations as part of the well-control equipment. However,DSSVs were addressed only in a very limited fashion in previousAPI specifications. The 38th edition of API Spec. 7, Section 2,Upper and Lower Kelly Valves,1 essentially addressed onlypressure-containment requirements for kelly valves that remainabove the BOP. For tension limits at the rated working pressure,temperature range for sealing, ability to close on backflow, oper-ating-torque characteristics, and fluid-compatibility information,operators had to rely on the manufacturers published data.

At the time this work was undertaken, no industry specifica-tions existed for DSSVs that could be used for stripping into a livewell below the BOPs, as required when a kick is taken duringtripping. For stripping applications, the stem seal of a DSSV musthold pressure from the outside because a slug of lower-densityinflux fluid in the annulus, the kick, results in a higher annuluspressure at the surface.

This investigation into problems associated with DSSVs beganin 1993 after several incidents were reported of stabbing valvesleaking downhole when stripped into wells under pressure. API-certified manufacturers of kelly valves were asked if they couldsupply engineering data to verify the suitability of their productsfor service conditions beyond the kelly valve requirements of APISpec. 7, Section 2. The results confirmed the need for improvedspecifications, particularly for full-bore stabbing valves.

In 1994, a survey of operators experiences with DSSVs con-firmed that there was a general industry need for an improvedvalve design to address the limitations of current designs, andDSSV manufacturers were invited to submit designs for a new-generation DSSV. One operator, Mobil, also approached API andobtained approval to form a DSSV task group to address the short-comings of the kelly valve specifications in Section 2 of API Spec.7. The DSSV task group was set up to report to the Drill StemComponents & Compounds Sub-Committee of the API DrillingStandards Committee.

In 1995, after the API task group developed the first draft of anew specification, a corresponding DSSV testing program wasproposed as a joint industry project (JIP), and the Gas ResearchInst. (GRI) agreed to be the major sponsor. Three manufacturersagreed to supply valves for the testing program. Results from thetesting program are discussed in this paper.

Identification of the ProblemAfter experiencing some leak problems through the stem seals ofball-type DSSVs that were stripped into a well under pressure, areview of DSSVs was initiated in 1993. The review was to estab-lish the design capabilities of valves made by different manufac-turers and to establish whether the leak problem experienced wasunique to one manufacturer or a more general problem. The resultsindicated that the majority of manufacturers were unaware of thedesign requirements for ball-type DSSVs used in well-control op-erations involving stripping because API specifications did notaddress the requirement to hold pressure across the stem seal fromthe outside.

In March 1994, as a follow-up to the review of manufacturers,a DSSV failure-frequency questionnaire was sent out by Mobil toa number of other operators. The results are presented in Table 1,in which the number of Xs indicates the relative frequency of thespecific failure types experienced. Based on the common problemslisted in Table 1, it was apparent that some were inherent to thebasic design of typical valves and that some occurred simply be-cause they were not addressed in relevant specifications.

A typical DSSV has a floating ball that is turned by a singlecrank 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 cur-rent designs or resulting from not being addressed in any of the1994 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 theclosing ball, including binding from misalignment of the ball andoperating stem and high ball-to-seat contact friction force.

Inability to open with high, near-equalized pressure. Hightorque results from the large end-load pressure force acting on thevery small thrust-bearing surface of the stem.

Limitations in the 1994 Industry Specificationsfor DSSVs

No requirement to hold the fluid pressure applied to theclosed valve from above.

No requirement to hold the fluid pressure applied to the out-side 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 valves body-material yield lim-

its 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.

Proposed API Specification RevisionsThe 1994 edition of API Spec. 7, Section 2, included no functionalperformance or prototype testing requirements for DSSVs. Toremedy this, in July 1994, Mobil proposed and received approvalto form an API DSSV task group to develop appropriate DSSVfunctional specifications. Mobil chaired the DSSV task group and

*Now with Shell Intl. Exploration and Production Inc.**Now with Hamburger Gaswerke GmbH.Now with the automotive industry.

Copyright 2003 Society of Petroleum Engineers

This paper (SPE 85727) was revised for publication from paper SPE 39320, first presentedat the 1998 IADC/SPE Drilling Conference, Dallas, 36 March. Original manuscript receivedfor review 23 February 1999. Revised manuscript received 10 June 2003. Paper peerapproved 11 June 2003.

256 September 2003 SPE Drilling & Completion

invited other operators, drilling contractors, manufacturers, valveanalysis and testing companies, and industry well-control expertsto participate.

The first draft of the revised specification was completed inSeptember 1995. The final version was presented to the Drill StemComponents & Compounds Sub-Committee of the API DrillingStandards Committee at the API Annual Meeting in June 1996 andwas approved for balloting. Although enough votes were cast infavor of adopting the new specification, the ballot failed becausecomments received were substantial and persuasive, requiringmore work within the API subcommittee. The comments werefocused on ensuring that many kelly-valve manufacturers wouldbe able to supply valves with the new requirements. The requiredrevisions were submitted after the valve-testing work was com-pleted in time for reballoting in 1998.

The proposed new specification was created to allow operatorsand drilling contractors to better specify their requirements forDSSVs. For example, the proposed new specification categorizedDSSVs into two classes of service, as shown in Table 2.

Class 1 for valves intended for surface-only applica-tions (restricted to the upper kelly valve or actuated top-drivevalve applications).

Class 2 for valves intended for all potential downhole appli-cations (designed to cover lower kelly valves and stabbing valvesthat may be stripped into a well under pressure).

The then-current API specifications really only addressedvalves intended to remain above the BOP (Class 1 in Table 2). Theproposed new specifications also covered valves that may bestripped into the well (Class 2 in Table 2). Note that for strippingapplications, it was anticipated that there could be a requirementfor rigging up and pressure testing a wireline lubricator on top ofa ball-type DSSV, hence the need to hold the working pressurefrom above. Also, it was anticipated that the annulus pressurescould be higher than the internal drillpipe pressure in strippingoperations. However, the resulting differential pressure is unlikelyto be as high as the working pressure of the valve. Hence, aminimum external pressure rating of 2,000 psi was proposed. (Thiswas not intended to prevent manufacturers from designing valveswith a higher external pressure rating but as a practical startingpoint for valve testing.)

In addition to the leak testing to verify the Class 2 functionalrequirements, five optional prototype performance-testing sectionswere initially proposed to API for either Class 1 or Class 2 valves.Key elements of the proposed optional prototype testing includedverifying the following.

Temperature range for pressure sealing. Gas-tight sealing. No loss of seal integrity after 500 cycles (close and open) in

circulating loop with weighted, sandy, water-based mud. Ability to manually close on mud flow. Ability to manually open with high internal, near-equal-

ized pressure. Tension range for sealing on the stem.Also, a supplemental material requirement was proposed to

provide a definition for H2S Trim valves. Reporting require-ments proposed included a chart, similar to Fig. 2, that indicatedthe valve bodys operational limits (initial yield condition) undercombined tension, torque, pressure, and bending loads. Additionalmarking requirements were also proposed to correspond with thenew performance testing.

Valves Selected for Testing

In August 1994, eight major ball-valve manufacturers were in-vited to submit design proposals for a new-generation DSSV thatwould address the shortcomings identified. It was envisioned thatfunding for testing of the most promising new designs would bethrough a JIP.

Only one manufacturer proposed a new DSSV design. (Tosome extent, this reflected the lack of financial incentive in thishistorically price-driven sector of the service industry.) The newDSSV included a trunnion bearing-mounted ball with floatingseats, features that are commonly used in high-pressure pipeline-service ball valves. The ball was rigidly mounted on the two op-erating stems so that the pressure loads would be transferred intothe body of the valve through the trunnion bearings rather thanthrough the seats. With the stems rigidly attached to the ball, thetorque required to operate Manufacturer As new ball valve wasexpected to be low compared with typical DSSVs while closingon flow or while opening with high, near-equalized pressuresacross the ball.

A JIP to evaluate the new valve design was proposed in Feb-ruary 1995 as DEA-100. Manufacturer A was to build and shoptest (at the projects expense) a 10,000-psi working pressure, 7-in.-outer-diameter (OD) 213/16-in.-inside-diameter (ID) prototypeDSSV. An independent testing facility was to be used to evaluatethe valve with the testing proposed in the API Spec. 7 revisionsballoted in 1996.

Interest in the project was not solidified until August 1995,when a second manufacturer agreed to supply their already com-

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Fig. 1Typical one-piece body, floating-ball DSSV configuration.

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mercial, new-generation floating-ball-type DSSV for evaluation.Valve B was a 10,000-psi working pressure, 7-in.-OD 213/16-in.-ID double-crank, floating-ball configuration with two H2S trimvalves in a single housing. Essentially, this was the tandem ballvalve design being supplied to a portable-top-drive manufacturer,as shown in Fig. 3.

The evaluation of the two valve designs (A and B) was set upas a GRI project because the majority of the JIP funding was tocome from the Institute. GRIs interest was to ensure that new-generation DSSVs, capable of meeting all the performance stan-dards proposed in the revised API specifications, would be avail-able to improve safety in future deep-gas drilling in the U.S.A.

The objectives of the project were to establish if the proposedrevisions to API Spec. 7, Section 2, were workable and if thenew-generation valves being evaluated could satisfy the require-ments for both the proposed Class 2 sealing and the prototypeperformance testing. The independent testing of the valves wassubcontracted to ITE Engineering, Clausthal, a contract testingfacility at the Inst. of Petroleum Engineering, Technical U. ofClausthal, Germany, which was then well known for its pipe andconnection testing work for the oil and gas industry.

Building the necessary fixtures and fittings to conduct the test-ing at ITE Engineering was completed in October 1995, and test-ing of the valve from Manufacturer B began in November 1995.Valve A testing began in December 1995 and confirmed the ex-pected low-torque characteristics, but deflection-related problemswith the trunnions could not be resolved.

While Manufacturer A was considering other design alterna-tives, a third manufacturer (Manufacturer C) was invited to supplya 10,000-psi-working-pressure, 7-in.-OD 234-in.-ID commercialvalve for testing, as shown in Fig. 4. Manufacturer C introduced alow-friction stem-bearing feature into their floating-ball, canister-design DSSV that had been shown, by testing in a student project3

at Louisiana State U., Baton Rouge, Louisiana, to significantlyreduce the torque required to close it on flow or to open it withhigh, near-equalized pressure. Testing of Manufacturer Cs valvebegan in October 1996, but a strength problem with the canisterlegs when working pressure was applied from above led to delaysin completion of the testing. In the meantime, Manufacturer Asupplied a 10,000-psi-working-pressure, 7-in.-OD 213/16-in.-ID,new-generation, modified floating-ball DSSV for testing in No-vember 1996 (as shown in Fig. 5).

Valve Testing Plan1. The testing program was broken into the following phases.2. Initial seat and seal leak test with water and nitrogen.3. Mud-solids contamination test.4. Repeat seat and seal leak test with water and nitrogen.5. Operating testclosing on flow.6. Operating testopening with near-equalized pressure.

7. Repeat seat and seal leak test (including tension).8. Post-testing examination of DSSV.For manual valve operation, a hexagonal bar-type wrench is

inserted into one (or both) of the corresponding hexagon-shapedoperating stems and rotated a quarter turn to operate the ball to thefully open or fully closed position. (The direction of the quarterturn depends on which operating stem is used.) In the testingprogram, a hydraulic actuator was connected through a crank to a

Fig. 2Proposed format for reporting valve-body initial-yieldcondition.

Fig. 3Valve B with a one-piece body, twin floating-ball DSSVdesign.

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hexagonal bar inserted into one of the operating stems on thevalve. Stops on the actuator were adjusted to provide ap-proximately 200 ft-lb of torque against the internal end stops ofthe valve.

To permit external pressure to be applied to the valve, an ex-ternal pressure sleeve, or autoclave, had to be fabricated. Theoperating stem of the actuator was sealed where it passed throughthe pressure sleeve, and the actuator was mounted directly onto thepressure sleeve. Fig. 6 shows the general configuration of theautoclave/actuator test-fixture arrangement used in all test-ing phases.

Fig. 7 shows the configuration of the circulating test loop usedin Phase 2 of the testing, and Fig. 8 shows the general equipmentlayout used in Phases 4 and 5.

Valve Testing ResultsInitial Seat and Seal Leak Test With Water and Nitrogen. Thistest established if the valve could satisfy the requirements of Class2 service in the operating temperature range of 14 to 194F anddetermined if the valves could be classified as gastight. Table 3

summarizes the results. Note that the acceptance criterion was nodetectable leakage. The minimum detectable leakage volume wasnot rigorously defined but was extremely small.

Basically, this initial seat test proved that the new-conditionvalves, as supplied, could all:

Be classified as a Class 2 type valves (i.e., suitable for surfaceand downhole stripping applications under the proposed new APIspecifications for drillstem valves). (That is, they held a 10,000-psiworking pressure from both below and above and 2,000 psi fromthe outside at ambient temperature with water.)

Be classified as suitable for Class 2 service in the temperaturerange of 14 to 194F (Valves A and B) and 14 to 150F (Valve C).(Valve C had canister seal problems at 194F.)

Be classified as gastight designs. (Valves B and C bothleaked at 250 psi nitrogen pressure when the pressure was appliedfrom the top. However, both valves were gastight when the pres-sure was applied from the bottom, which is the critical direction forcontaining well fluids.)

Mud Solids Contamination Test. This phase was designed toestablish if any loss of sealing integrity would occur because ofoperating the valve as a mud-saver valve. (This is a commonpractice when two DSSVs are employedone is used as a mud-

Fig. 4Valve C, low-friction, stem-bearing, canister-type DSSVdesign.

Fig. 5Valve A, modified floating-ball DSSV design.

260 September 2003 SPE Drilling & Completion

saver valve to prevent mud spillage onto the rig floor each time aconnection is made.) To simulate the mud-saver working environ-ment, a 16-lb/gal, sandy, water-based mud was circulated throughthe valve for 100 hours in the normal mud flow direction, and thevalve was operated 500 times. The mud was formulated with freshwater, 0.5% by volume 120-mesh sand, bentonite, and polymer, asrequired to suspend the barite weighting material. (See Table 4 fora summary of the mud properties.)

A purpose-built flow loop was used to flow mud with a tem-perature of 150F and a pressure of 500 psi at 100 gal/min throughthe valve. The flow was stopped each time the valve was to beoperated (closed and opened). The actuator moved the stem aquarter turn in approximately 2 seconds to simulate normal manualopening (or closing) speed, and the torque required to open andclose was recorded for each of the 500 cycles.

The low flow rate used was not intended to investigate theresistance of the valve to mud-flow erosion because erosion wouldonly be expected if the bore of the ball was not in good align-ment. However, a visual check on the balls alignment in theindicated open position was made at the end of the 100-hour flowloop testing.

Table 4 summarizes the results. This mud-saver application testproved that all three valves could:

Be operated manually for 500 close-and-open cycles in a16-lb/gal, sandy, water-based mud without a serious increase intorque. (The opening torque increased more than the closing torque,but both stayed at less than 300 ft-lb.) Of the three valves, Valve Cexhibited the most consistent torque values throughout the 500 cycles.

Maintain good alignment of the ball in the indicated openposition when a torque of 200 ft-lb was applied to the internal endstops during 500 close-and-open cycles.

Repeat Seat and Seal Leak Test. Table 5 summarizes the resultsof the repeat seat and seal leak test. Basically, this test proved thefollowing after simulated use as a mud-saver valve.

Valve B could not provide water- or gastight sealing at work-ing pressure applied from the top or bottom at ambient tempera-ture. (Trapped mud solids interfered with ball/seat sealing.)

Valve C could still provide water- and gastight sealing forbottom and externally applied pressures at ambient temperature.(The canister leg deformed when pressure was applied from thetop of the valve. This essentially terminated testing until a designchange could be implemented.)

Valve A could still provide new-condition water- andgastight sealing for top, bottom, and externally applied pressures atambient temperature.

Operating TestClosing on Flow. This phase of the testingwas to determine the torque required to close the valve and shutoff a flow of 16-lb/gal, sandy, water-based mud. Two flow rateswere used to establish a relationship between the backflow rateand the torque required to close the valve. A closure speed of2 seconds was used to simulate manual operation, and the actuatorcould generate up to 700 ft-lbf of torque. A bypass line andchoke arrangement were used to limit the pressure buildupto approximately 2,000 psi when the valve was closed. Torquevalues recorded included approximately 35 ft-lbf of torquefrom the friction of the actuator stem turning in the pressuresleeve seal.

Table 6 summarizes the results. While closing, the torque in-creased rapidly during the last 10 of stem rotation. Similarly, forthe test in which the valve was opened successfully, the torquedropped off rapidly during the first 10 of stem rotation. Note thata maximum operating torque of 400 ft-lbf was suggested as theupper limit for manual operation in the draft proposal to API. (Thiswas based on the limit for manually operating a valve that is easilyaccessible from the rig floor and when a 4-ft operating handle isused.) Lower operating torques are desirable for manual operationwhen the valve is not easily accessible from the rig floor or whena shorter lever arm is used.

Fig. 6General configuration of the valve testing fixture.

261September 2003 SPE Drilling & Completion

Basically, closing on mud backflow from the drillstring oper-ating test proved the following after simulated use as a mud-saver valve.

Only Valve A could be reliably closed on a mud backflow ofup to 200 gal/min without exceeding 400 ft-lbf of closing torque.

None of the valves could be reliably reopened manually (re-corded torques were greater than the proposed 400 ft-lbf limit)after closing on the mud backflow, and the differential pressureacross the ball was built up to 2,000 psi.

Operating TestOpening Under Pressure. In the industrysurvey of problems, abnormally high torques were reported thatprevented manual operation when attempting to open ball-type DSSVs with high pressure inside the valve, even if it wasequalized to some degree. This testing phase was to determinethe torque required to open the valve under a variety of in-ternal pressure conditions created first with water and then with16-lb/gal, sandy, water-based mud. Table 7 summarizesthe results.

This operating test for opening with internal pressure basicallyproved the following for both Valves A and B after simulated useas mud-saver valves.

The valves could be opened manually (recorded torque wasless than 435 ft-lbf) with equalized pressures of up to 10,000 psiwith water and 5,000 psi with sandy, 16-lb/gal mud.

The valves could not be opened manually (recordedtorque was greater than 435 ft-lbf) with a differential pressure of2,000 psi across the ball, regardless of the absolute pressures or thetest fluid.

Repeat Seat and Seal Leak Test (Includes Tension). In thisfinal testing phase, tension was included to establish if the stemseal-system integrity was dependent on the tension applied to the

Fig. 8Equipment layout for closing on mud backflow andopening under pressure.

Fig. 7Configuration of the mud circulation flow loop (M = motor).

262 September 2003 SPE Drilling & Completion

valve body at ambient and at high temperatures. Table 8 summa-rizes the tension-testing results.

This repeat seat and seal leak test with tension and hightemperature proved the following after simulated use as a mud-saver valve.

All three valves could provide watertight sealing from in-side and outside at ambient temperatures with 500,000 lb of ten-sion applied to the valve body. (The stem seals were stillfully effective.)

Valve A provided watertight sealing from inside and outsideat a high temperature (194F) with 500,000 lb of tension applied tothe valve body.

Valve B could not provide watertight sealing from outside ata high temperature (189F) with 500,000 lb of tension applied tothe valve body. (The stem seals failed.)

Post-Testing Examination of DSSV. Valve A. Because thetorque data from opening with near-equalized pressure (Phase 5)was difficult to interpret, a more comprehensive opening series ofnear-equalized pressure tests was conducted with both water and16-lb/gal sandy mud. This allowed the opening torque to be char-acterized by two componentsmaximum and differential pressurecomponents, both of which were impacted by fluid type. Resultsfor water and mud were plotted as shown in Figs. 9 and 10 toseparate the two components of opening torque.

Valve B. Valve B was disassembled and examined for wear,stem seal condition, and mechanical distortion. Only minor, abra-sion-type wear was found on the ball and seats after cleaning offthe adhering mud solids (bentonite, barite, and sand particles). Oneof the stem seal O rings had failed in the tension test, which wasconfirmed by visual examination. The only distortion observedwas in the area of the valve position stops on the inside end of thestems. The distortion resulted in the end part of each stem beingswagged into contact with the end of the stem holes.

After cleaning and replacing the failed stem seal, the valve wasreassembled and leak tested, with no leakage to 10,000 psi withwater. This confirmed the role of mud solids in preventing thevalve from sealing pressure applied from above or below the ballin all the tests after 100 hours of operating in a 16-lb/gal, sandymud. Hence, when used as a mud-saver valve, mud solids foulingthe sealing surfaces can compromise the sealing ability of thisDSSV type.

Opening torques measured after cleaning and reassembly of thetested valve with damaged stems essentially matched the higher-than-expected operating torques seen in the testing with water,which were somewhat higher than those measured with a new-condition valve. Hence, the stem damage sustained in the simu-lated mud-saver testing contributed to the high torques seen later.

Manufacturer B redesigned the stem, insert, and internal valve-stop configuration used in its DSSVs to address the damage thatwas caused by the 500 operations (close and open) with approxi-

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264 September 2003 SPE Drilling & Completion

mately 200 ft-lbf of torque applied to the end stops. It reports thatthe improved valve design has also reduced the operating torque.

Valve C. The canister leg on the stem side of Valve C wasdeformed during initial leak testing at high temperatures withworking pressure applied from above. The same failure occurred inthe replacement canister during repeat leak testing after complet-ing the mud-solids contamination test. The canister design hadbeen considered adequate for this load condition, but it did notperform as designed. The investment castings used for the canisterapparently had a lower-than-anticipated compressive strength, per-haps because of poor grain structure. A new canister, made frombillet stock of the same material type and strength, was tested incompression to confirm its design load capacity before being as-sembled into the rebuilt valve used in Phases 4 through 7 of thetesting program.

Conclusions1. Many of the problems the oil and gas industry has seen with

DSSVs can be traced back to the lack of an adequate func-tional specification.

2. The functional specifications proposed by APIs DSSV taskgroup were found to be workable, as demonstrated by its appli-

cation in the evaluation of three new-generation, floating-ball-type DSSVs supplied for testing.

3. The testing has demonstrated that it is feasible to build DSSVssuitable for surface and downhole (stripping) service that haveall the following verified functionalities.a. Gastight sealing in the new condition.b. Useful operating temperature and tension range for sealing.c. Reasonable service life in the drilling-mud environment.d. Reasonable torques for closing on mud backflow or openingwith near-equalized pressure.

4. Using a DSSV similar to Valve B as a mud-saver valvecan result in mud-solids fouling, which can compromise thevalves pressure-sealing ability. (Hence, when such a valve isused as a mud-saver valve with a kelly or overhead drillingsystem, a second DSSV would need to be run below it to pro-vide reliable drillstring pressure sealing in the event of a well-control incident.)

5. Low-torque operation of floating-ball-type DSSVs for closingon backflow or opening with high internal pressure is difficult toachieve, especially in the heavy-weight, sandy, water-based-mud environment used in this testing program.

6. Testing has aided all three participating DSSV manufacturers byproviding tangible new insights into refinements needed for the

Fig. 10Comprehensive additional opening with near-equalized pressure-testing results for Valve A with 16-lb/gal sandy mud.Comparing the results obtained with water, shown in Fig. 9, it is evident that both components of the opening torque are influencedby the fluid environment.

Fig. 9Comprehensive additional opening with near-equalized pressure-testing results for Valve A with water. Graphical presen-tation clearly shows two components of opening torquemaximum and differential pressure components.

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valves to meet all the functional specifications evaluated inthe testing.

7. An independent testing facility for testing DSSVs to the pro-posed new functional specification was established. However,subsequent staff changes at Clausthal U. have since resulted inthe testing facility being closed.

Final CommentsThe JIP report was subsequently published in 1998 by GRI.4 How-ever, it took a few more years of discussion within the API sub-committee before any of the proposed revisions were finally pub-lished in the 40th edition of API Spec. 7.5 The following recom-mendations were included.

The proposed pressure-containment classifications (Class 1and Class 2).

An optional qualification procedure for gastight sealing. The option for the purchaser to specify the required tempera-

ture range for sealing.No requirements to verify the sealing pressure under tension

loading, the seal after repeated operation in mud, open under lim-ited differential pressure (with acceptable torque), or close on alimited backflow (with acceptable torque) are included in the 40thedition of API Spec. 7 because these items were considered asfeatures not generally available for existing valve designs.

Hence, progress has been made in improving industry specifi-cations for DSSVs, but even the latest specifications still do notaddress some of their known problems.

AcknowledgmentsThe authors wish to thank the members and contributors to the APIDrill String Safety Valve Task Group, including Dr. Ted Bour-goyne, Louisiana State U.; Stephen Howard, Howard & Assoc.;Paul Spencer, South West Research; Vance Keiffer, Oilfield AuditServices; Bill Archibald, Sante Fe Drilling; Gregory Renfro,VARCO; Carl Hock, SONAT; Bill Carbough and Gary Kirsch,Hydril; Bill Shock, OMSCO; and Glenn Armstrong, EngineeringDesign & Testing Corp. The majority of the funding for the testingwork reported in this paper was provided through GRI ContractNo. 5095-210-3526.

References1. Spec. 7, Rotary Drill Stem Elements, 38th edition, API, Washington,

DC (1994).

2. AMOCO DSSV testing data, Mobil Drilling Newsletter (1994) No.28, 23.

3. Bourgoyne, A.T. et al.: Drill String Safety Valve Test Program,paper 21 presented at the 1996 LSU/MMS Well Control Workshop,Louisiana State U., Baton Rouge, Louisiana, 1920 November.

4. Tarr, B.A.: Drill String Safety Valve Development and Testing, GRIReport 98/0229, Gas Research Inst. (1998).

5. Spec. 7, Rotary Drill Stem Elements, 40th edition, API Washington, DC(November 2001).

SI Metric Conversion Factorscp 1.0* E03 Pasin. 2.54* E+00 cmft 3.048* E01 m

ft2 9.290 304* E02 m2

ft-lbf 1.355 818 E+00 NmF (F32)/1.8 C

gal 3.785 412 E03 m3

gal/min 6.309 020 E02 m3/slbf 4.448 222 E+00 N

lb/gal 1.198 264 E+02 kg/m3

psi 6.894 757 E+00 kPa

*Conversion factor is exact.

Brian Tarr is now a senior projects engineer in the DeepwaterWell Delivery unit of Shell International Exploration and Produc-tion Inc., Houston. e-mail: brian.tarr@shell.com. Since 2001, hehas been responsible for managing the development of inno-vative deepwater drilling technologies. His previous experi-ence with Mobil and ExxonMobil included direct involvementin managing offshore drilling and production operations in theU.K. sector of the North Sea, providing drilling engineering sup-port to drilling operations worldwide, managing innovativedrilling-technology development and stewarding the applica-tion of novel drilling and completion technologies. Tarr holdsan MS degree in petroleum engineering from Heriot-Watt U.,Edinburgh, U.K. He has been an SPE Technical Editor, a ReviewChairman, and the Executive Editor for SPE Drilling & Comple-tion. Ralf Luy is now head of the storage department of Ham-burger Gaswerke GmbH, Hamburg, Germany. At the time ofthe testing reported in this paper, he was chief engineer at theInst. of Petroleum Engineering, Clausthal, Germany. Luy holds aPhD degree in mining engineering from Clausthal U., Germany.Glen Rabby is the president and general manager of Hi-KalibreEquipment Ltd., Edmonton, Alberta, Canada. e-mail:glen@hikalibre.com. His entrepreneurial career spans farming,real estate, construction, and water-well drilling. It was his ex-tensive knowledge and passion for the oilfield industry that ledhim to establish Hi-Kalibre in 1986 as a company that strives tobe a worldwide leader in equipment manufacturing. HeinerKickermann is now employed in the automotive industry. Atthe time of the testing reported in this paper, he was respon-sible for the wellhead engineering group of Intl. Tiefbohr GmbH& Co. (ITAG), Celle, Germany. Kickermann holds a PhD degreein mechanical engineering from the Technical U. of Braunsch-weig, Germany. Jrg Senftleben is head of ITAGs engineeringand des ign department , Cel le , Germany. e-mai l :joerg.senftleben@itag-ce.de. He joined ITAGs engineeringdepartment as a project and design engineer for ball valves in1984. He was promoted to his current position in 1998. Senftle-ben holds a diploma in mechanical engineering from FH Han-over. Jim Cunningham is the operations manager for M&MIntl., New Iberia, Louisiana, and has been with the companysince 1991. e-mail: jim@mmvalve.com.

266 September 2003 SPE Drilling & Completion