Description
API 16A Annular BOP Packing Element for Drilling, Workover and Well Control
SGPE API 16A Annular BOP Packing Element forms the main flexible pressure seal inside an annular blowout preventer. Drilling contractors, oilfield service companies, well control specialists and BOP repair workshops use this reinforced rubber component during drilling, workover, completion, well testing and well intervention.
When the operator closes the annular BOP, hydraulic pressure moves the operating piston and compresses the packing element toward the center of the bore. The molded elastomer follows the tubular profile and creates a pressure-containing seal around drill pipe, tubing, casing, kelly, test strings, tool joints and other approved tool profiles.
Certain annular preventers can also close across an open bore when no tubular remains inside the BOP. However, the equipment model, packer geometry, hydraulic closing pressure and operating procedure determine the allowable open-bore pressure. In many designs, this pressure remains below the full rated working pressure of the preventer.
Available designs include spherical BOP packing elements, conical annular BOP packers and tube-shaped BOP rubber elements. Common FH model requirements include FH18-21, FH18-35, FH18-70, FH28-35, FH28-70, FH35-35 and FH35-70.
Each packing unit combines a molded elastomer body with reinforced steel inserts. The rubber forms the pressure barrier, while the inserts guide inward movement, distribute compression and control deformation. This construction allows the packer to follow several tubular profiles without losing the support required for well control service.
Customers can order the main packing element separately or together with piston seals, head seals, housing seals, opening and closing chamber seals, O-rings, wear rings, support rings, dust rings and other annular BOP replacement parts.
API 16A Annular BOP Packing Element Specifications
| Item | Available Specification |
|---|---|
| Product | API 16A Annular BOP Packing Element |
| Alternative Names | Annular BOP Packer, BOP Packing Unit, BOP Rubber Element, Spherical Rubber Core |
| Applicable Equipment | Spherical, conical and tube-type annular BOPs |
| Nominal Bore | 7-1/16 in to 21-1/4 in |
| Pressure Class | 2,000, 3,000, 5,000, 10,000 or selected 15,000 psi models |
| Common FH Series | FH18, FH28 and FH35 |
| Main Function | Seal around tubulars or close an open bore where the BOP design permits |
| Packing Construction | Molded elastomer with reinforced steel inserts |
| Elastomer Options | NBR, HNBR, high-temperature or application-specific compound |
| Sealing Profiles | Drill pipe, tubing, casing, kelly, test strings and approved tool joints |
| Working Media | Water-based mud, oil-based mud, synthetic mud, completion fluid, oil, gas, water and brine |
| Operating Service | Drilling, workover, completion, well testing and well intervention |
| Pipe Stripping | Subject to BOP model, pipe OD, tool joint OD, well pressure and operating procedure |
| Sour Service | Subject to H2S, CO2, temperature and fluid review |
| Manufacturing Basis | Applicable API 16A-related requirements agreed in the purchase order |
| Rubber Test Methods | ASTM D412, ASTM D624, ASTM D2240 and ASTM D471 when specified |
| Standard Inspection | Visual, dimensional, hardness and identification checks |
| Documentation | Certificate of Conformity, inspection report and agreed test records |
| Replacement Matching | Model, part number, nameplate, drawing, dimensions or physical sample |
| Related Supply | Annular BOP seal kits, repair parts and overhaul packages |
What Is an Annular BOP Packing Element?
An annular BOP packing element is the flexible sealing component installed inside an annular blowout preventer. Unlike a rigid metal seal, the packer changes shape when hydraulic pressure moves the BOP operating piston.
The piston compresses the elastomer inward from every direction. This circular closing movement allows one packing unit to seal around several tubular outside diameters within its approved operating range.
Depending on the BOP design, the element may seal around drill pipe, tubing, casing, kelly, test strings, intervention tools and selected tool joint profiles. Some annular BOPs also allow the packer to close across an empty bore.
Buyers use several names for this component, including annular BOP packer, BOP packing unit, annular preventer rubber element, spherical rubber core, blowout preventer sealing element and annular BOP rubber element.
These terms describe the same general product category, but they do not confirm interchangeability. The exact packer design changes with the BOP manufacturer, model, nominal bore, pressure class and internal operating geometry.
A suitable replacement must match the original outside profile, overall height, bore contour, steel insert arrangement and closing movement. Selecting an annular BOP replacement packer only by bore size or pressure rating creates a high risk of mismatch.
How an Annular BOP Packing Element Seals the Wellbore
During normal drilling, the annular BOP remains open so drill pipe, casing, tubing and downhole tools can move through the bore.
When the operator activates the closing circuit, hydraulic fluid enters the closing chamber and moves the piston. The piston compresses the packing element against the BOP head and housing.
As the packer moves inward, its steel inserts draw closer together and guide the rubber toward the center of the bore. Once the elastomer contacts the tubular, it forms a pressure-containing seal.
An annular BOP differs from a ram BOP. A ram preventer closes two opposing ram blocks. Pipe rams normally match a defined pipe size, while variable bore rams cover a limited range. Blind rams close an empty bore, and blind shear rams cut the tubular before sealing.
Because annular and ram BOPs use different internal structures and closing movements, an annular BOP rubber element cannot replace a pipe ram packer, variable bore ram rubber or blind shear ram seal.
The packing element contacts drilling fluid, formation fluid and moving tubular surfaces directly. Therefore, its dimensions, rubber formulation and insert structure affect sealing reliability, required closing pressure, tool joint passage, pipe-stripping performance, rubber recovery, extrusion resistance and service life.
An unsuitable elastomer may swell, harden, soften, crack or lose elasticity after exposure to oil-based mud, hydrocarbons, high temperature or aggressive additives. Likewise, an incorrectly sized packer may fit poorly, compress unevenly or require excessive hydraulic pressure.
Accurate replacement selection therefore requires more than a bore size and pressure rating. The review should also consider the exact BOP configuration, internal geometry, fluid system, temperature range and operating cycle.
Annular BOP Packing Element Design Comparison
| Design | Operating Profile | Main Characteristic | Typical Application |
| Spherical Packing Element | Curved or spherical surface | Steel inserts rotate inward as the piston moves | FH-type and spherical annular BOPs |
| Conical Packing Element | Inclined or tapered surface | The piston drives the elastomer along a cone | Conical annular preventers |
| Tube-Shaped Rubber Element | Cylindrical outer profile | Compression acts inward from the circumference | Model-specific annular BOPs |
| Compatible Replacement Packer | Matches existing BOP geometry | Identified by model, part number, drawing or sample | Repair, overhaul and obsolete-model replacement |
A shared bore size and pressure class do not guarantee interchangeability. The packer height, outside profile, bore shape, steel insert arrangement and piston movement must match the original annular BOP.
Spherical BOP Packing Element
A spherical BOP packing element works against a curved operating surface. As the piston moves, it drives the packer along the spherical profile. The steel inserts rotate inward and guide the elastomer toward the center of the bore.
This controlled movement distributes compression through the packing unit and helps the rubber form an even seal around the tubular.
| Item | Description |
| Product Type | Spherical BOP Packing Element |
| Operating Surface | Curved or spherical |
| Reinforcement | High-strength steel inserts |
| Closing Movement | Steel inserts rotate inward as the piston moves |
| Sealing Profiles | Approved drill pipe, tubing, casing and tool profiles |
| Typical Application | FH-type spherical annular BOPs |
| Common Series | FH18, FH28 and FH35 |
| Main Matching Data | Outside diameter, height, bore profile and insert structure |
Buyers may describe this product as a spherical annular BOP packer, FH BOP packing unit, FH rubber core or spherical rubber core.
Two spherical packers may look almost identical but still use different dimensions, insert angles, bore profiles or elastomer compounds. External appearance alone cannot confirm compatibility.
Common model-specific requirements include FH18-21 packing elements, FH18-35 packing elements, FH18-70 packing elements, FH28-35 annular BOP packers, FH28-70 annular BOP packers, FH35-35 spherical rubber cores and FH35-70 spherical BOP packing elements.
For accurate identification, provide the complete BOP nameplate, pressure class, original part number and measurements of the existing packing unit.
Conical Annular BOP Packing Element
A conical annular BOP packing element works against an inclined or tapered operating surface. As the piston moves, it pushes the reinforced elastomer along the cone and toward the center of the bore.
This movement controls rubber flow and steel insert travel during closing. The packer can seal around drill pipe, tubing, casing and other approved tubular profiles.
A conical packer cannot replace a spherical packing element simply because both products share the same nominal bore and pressure class. Their operating surfaces, piston contact areas and closing movements remain different.
The replacement must match the original operating angle, outside diameter, overall height, inner bore profile, piston contact surface, insert quantity, insert spacing and rubber compound.
Use the complete BOP model, original part number, technical drawing or verified dimensions to confirm a conical annular BOP replacement packer.
Tube-Shaped Annular BOP Rubber Element
Some annular preventers use a cylindrical or tube-shaped rubber element. The operating mechanism compresses the packer inward from its outer circumference.
Tube-shaped annular BOP rubber elements vary considerably between equipment designs. Differences may include the outside profile, end-face shape, bore contour, reinforcement layout and elastomer formulation.
The original part number, equipment drawing, detailed dimensions or physical sample should guide the replacement review. Bore size alone does not provide enough information.
Packing Element Construction
Molded Elastomer Body
The molded elastomer body provides the flexibility required to seal around several tubular diameters and profiles. It also forms the main pressure barrier inside the annular BOP.
During operation, the rubber must deform under hydraulic force, follow the tubular surface and recover when the BOP opens. Its formulation therefore affects sealing, pipe stripping, fluid resistance and service life.
Compound selection should consider the drilling or completion fluid, wellbore fluid, hydrocarbon concentration, operating temperature, closing frequency, stripping requirement and expected H2S or CO2 exposure.
Hardness alone cannot confirm suitability. Two compounds with the same durometer value may react differently in hot oil-based mud, synthetic drilling fluid, concentrated brine or aggressive chemicals.
A formulation suitable for standard land drilling may not suit high-temperature well testing, sour gas service or repeated tool joint stripping.
Reinforced Steel Inserts
Steel inserts support the elastomer and guide it toward the bore center. They also distribute compression and help control rubber extrusion.
The insert profile, angle, quantity and spacing must follow the original design. Even small differences can change rubber flow, tubular contact, closing movement, recovery and installation fit.
The rubber-to-metal bond also affects packer performance. Controlled steel preparation, molding pressure, curing temperature and curing time help create a stable reinforced structure.
Loose, exposed or poorly bonded inserts may reduce sealing performance and can damage the annular preventer during operation.
Annular BOP Elastomer Selection Guide
| Elastomer Option | General Characteristics | Typical Selection Factors |
| NBR Packing Element | Suitable for many conventional petroleum fluids and drilling environments | Standard drilling, moderate temperatures and general well control |
| HNBR Packing Element | Improved mechanical strength and temperature resistance in selected applications | Elevated temperatures, frequent closing cycles and demanding service |
| Application-Specific Elastomer | Formulated for defined fluid and temperature exposure | Synthetic mud, aggressive additives and project-specific fluids |
| Sour-Service Compound | Reviewed against H2S, CO2, pressure, temperature and fluid conditions | Sour oil and gas wells after technical review |
| High-Temperature Compound | Selected according to continuous and peak temperature exposure | High-temperature drilling, completion or well testing |
NBR Annular BOP Packing Element
NBR remains a common choice for annular BOP packers used in conventional drilling environments. It can suit many petroleum fluids, water-based drilling muds and moderate temperatures.
However, actual performance depends on the formulation, curing system, hardness and fluid resistance. A generic NBR description does not guarantee compatibility with every drilling fluid or temperature range.
HNBR Annular BOP Packer
HNBR may offer improved mechanical strength and temperature resistance in selected drilling, workover and well testing applications.
It may suit equipment that experiences elevated temperatures, repeated closing cycles or controlled pipe stripping. Even so, the material review should consider the mud system, hydrocarbon exposure, well pressure and expected operating cycle.
High-Temperature Packing Element
A high-temperature annular BOP packing element requires more than a general temperature label.
The selection should consider continuous temperature, short-term peak temperature, exposure time, fluid type, pressure, closing frequency and storage history.
A compound that tolerates brief heat exposure may not provide the same performance during extended high-temperature drilling, completion or well testing.
Sour-Service Annular BOP Packer
For H2S or CO2 service, provide the gas concentrations, pressure, operating temperature, drilling or completion fluid and project specification.
A sour-service rubber compound only addresses the packing element. It does not automatically qualify the complete BOP for every sour-service or NACE-related requirement.
The BOP body, metallic components, fasteners, piston seals, housing seals, hydraulic seals, material certificates and equipment documentation may require separate review.
Closing and Opening Cycle
Closing Cycle
Hydraulic fluid enters the closing chamber and moves the operating piston. The piston compresses the packing element against the BOP head and housing.
As the steel inserts move inward, they guide the elastomer toward the center of the bore. Once the rubber contacts the tubular, it forms a pressure-containing seal.
Operators should apply only the hydraulic pressure required to maintain a stable seal. Excessive closing pressure increases internal stress, accelerates wear and may shorten packer life.
On annular BOPs designed for open-bore closure, the element can continue moving inward until it closes the empty bore.
Opening Cycle
To reopen the BOP, the hydraulic system releases closing pressure and directs control fluid to the opening chamber.
The piston returns to its open position, while the rubber’s elasticity helps the packer recover its original shape. Drill pipe, tubing, casing and downhole tools can then pass through the bore.
Insufficient closing pressure may fail to create a stable seal. In contrast, excessive pressure may cause permanent deformation, internal cracking or poor recovery.
Open-Bore Closure and Empty-Bore Sealing
Many buyers need an annular BOP packing element that can close across an open bore. RFQs may describe this requirement as an open-bore annular BOP packer, open-hole BOP packing element, empty-bore sealing element or full-bore closing packing unit.
Not every annular preventer supports the same open-bore pressure. In many designs, the allowable pressure across an empty bore remains below the full working pressure marked on the BOP.
Before relying on open-bore closure, confirm the exact BOP model, nominal bore, pressure class, packer design, required hydraulic closing pressure and original operating procedure.
The replacement element must match the original geometry. Operators should also follow the pressure limits stated in the equipment manual and approved well control program.
Tool Joint Sealing and Pipe Stripping
Certain annular BOP packers can seal around drill pipe tool joints and support controlled pipe stripping.
During stripping, the packer expands and contracts as the smaller pipe body and larger tool joint profiles move through the closed bore. This movement creates friction, heat and repeated rubber deformation.
The technical review should consider the drill pipe outside diameter, tool joint outside diameter, maximum passing profile, well pressure, stripping speed, hydraulic closing pressure, lubricant and expected stripping frequency.
Large tool joints create more friction than the pipe body. Excessive closing pressure, unsuitable lubricant or repeated high-load stripping may cut, overheat or permanently deform the elastomer.
Operators should follow the original equipment procedure and inspect the packer after difficult stripping, unusual resistance or visible surface damage.
Common FH Annular BOP Packing Element Models
| BOP Model | Nominal Bore | Pressure Class | Typical Oilfield Use |
| FH18-21 | 180 mm / 7-1/16 in | 21 MPa / 3,000 psi | Small-bore drilling and workover |
| FH18-35 | 180 mm / 7-1/16 in | 35 MPa / 5,000 psi | Standard drilling and well control |
| FH18-70 | 180 mm / 7-1/16 in | 70 MPa / 10,000 psi | High-pressure small-bore service |
| FH28-35 | 280 mm / 11 in | 35 MPa / 5,000 psi | Land rig and workover BOP stacks |
| FH28-70 | 280 mm / 11 in | 70 MPa / 10,000 psi | High-pressure drilling operations |
| FH35-35 | Approx. 346 mm / 13-5/8 in | 35 MPa / 5,000 psi | Large-bore land and offshore drilling |
| FH35-70 | Approx. 346 mm / 13-5/8 in | 70 MPa / 10,000 psi | High-pressure large-bore well control |
This table provides a general model reference rather than a universal interchangeability chart.
Manufacturers and design revisions may use different dimensions, weights, insert arrangements and rubber formulations. Before production, compare the outside diameter, overall height, bore profile, insert configuration and product markings with the original equipment.
Available Annular BOP Packer Sizes and Pressure Ratings
| Nominal BOP Bore | Common Pressure Options | Typical Purchase Description |
| 7-1/16 in | 3,000, 5,000 or 10,000 psi | 7-1/16 Annular BOP Packing Element |
| 9 in | 3,000 or 5,000 psi | 9 Inch Annular BOP Packer |
| 11 in | 3,000, 5,000 or 10,000 psi | 11 Inch 5K or 10K BOP Packing Unit |
| 13-5/8 in | 3,000, 5,000, 10,000 or selected 15,000 psi | 13-5/8 Annular BOP Packing Element |
| 16-3/4 in | 3,000, 5,000 or model-specific higher ratings | 16-3/4 Annular Preventer Rubber Element |
| 18-3/4 in | 5,000, 10,000 or selected 15,000 psi | 18-3/4 Annular BOP Replacement Packer |
| 20-3/4 in | Project-specific | 20-3/4 Annular BOP Packing Unit |
| 21-1/4 in | 2,000, 3,000 or 5,000 psi | 21-1/4 Annular BOP Rubber Element |
Common purchase descriptions include an 11 inch 5K annular BOP packing unit, an 11 inch 10K annular BOP packer, a 13-5/8 inch spherical rubber core, an 18-3/4 inch replacement packing element and a high-pressure 10K annular BOP rubber element.
Not every bore size supports every pressure class. The complete BOP model, nameplate and design revision should control the final selection.
Oil and Gas Industry Applications
| Application | Equipment Environment | Packing Element Function |
| Land Drilling | Exploration and development drilling rigs | Seal around drill pipe, kelly and tool joints during kick control |
| Offshore Drilling | Jack-up, platform and offshore drilling systems | Maintain annular sealing under model-specific conditions |
| Workover | Tubing pulling, casing work and well repair | Seal around tubing, casing and service tools |
| Well Completion | Completion string and production tubing installation | Maintain pressure control around completion tubulars |
| Well Testing | Drill stem testing and surface well testing | Seal around test strings and tubulars |
| Well Intervention | Fishing, milling, cleanout and tool recovery | Support pressure control around intervention strings |
| Pipe Stripping | Controlled tubular movement through a closed BOP | Maintain sealing around pipe bodies and tool joints |
| BOP Overhaul | Repair workshops and recertification facilities | Replace worn, aged or damaged packing elements |
| Emergency Spare Supply | Rig base, warehouse or offshore facility | Reduce downtime after packer damage or pressure-test failure |
During drilling, the packer creates a flexible seal around drill pipe, kelly and selected tool joints. During workover, it may seal around production tubing, casing, work strings or service tools.
Completion and well testing operations may expose the rubber to brine, hydrocarbons, changing temperatures and repeated pressure cycles. The compound should match these operating conditions rather than only the nominal BOP pressure class.
BOP repair workshops commonly replace annular BOP rubber elements after cuts, swelling, exposed inserts, poor recovery or pressure-test leakage.
Compatible Annular BOP Replacement Packers
SGPE reviews replacement requirements for FH-type spherical BOPs and common Hydril-type, Shaffer-type, Cameron-type and other international annular preventer configurations.
The same bore and pressure class do not confirm interchangeability. Different BOP designs may use different outside profiles, packer heights, bore contours, steel insert arrangements, piston contact surfaces, elastomer compounds and closing movements.
Send the exact BOP model, original part number, nameplate photograph, technical drawing or existing packer measurements. These details allow the technical team to compare the replacement geometry with the original equipment.
A compatible replacement packer does not mean that SGPE acts as the original manufacturer or an authorized representative of Hydril, Shaffer, Cameron or another third-party brand.
Replacement Matching by Model, Drawing or Physical Sample
The original part number and exact BOP model provide the most reliable basis for replacement selection.
When this information is unavailable, clear product photographs and measurements can support identification. Useful data include the outside diameter, overall height, inner bore diameter, bore contour, top and bottom profiles, insert quantity, insert angle and visible product markings.
A physical sample may also help, but service wear can change its original dimensions. Rubber may swell, shrink, crack or remain permanently compressed after long-term use.
Compare measurements from a worn sample with the equipment configuration, installation space, available drawings and previous purchase records before confirming production dimensions.
Photographs should clearly show the top, bottom, side profile, bore shape, steel insert arrangement and any identification marks.
How to Select the Correct API 16A Annular BOP Packing Element
Selecting an annular BOP packer by bore size alone creates a high risk of mismatch. Two preventers with the same nominal bore and pressure class may use different internal profiles, heights and insert arrangements.
| Selection Item | Information Required | Why It Matters |
| Equipment Identification | BOP manufacturer, exact model and nameplate | Identifies the original design |
| Size and Pressure | Nominal bore and rated working pressure | Confirms the basic configuration |
| Original Reference | Original or existing replacement part number | Speeds up product matching |
| Existing Packer Data | Photographs, drawing, dimensions or physical sample | Confirms the actual geometry |
| Packer Structure | Spherical, conical or tube-shaped | Identifies the operating profile |
| Main Dimensions | Outside diameter, overall height and inner bore profile | Confirms installation fit |
| Operating Conditions | Temperature, fluid and closing frequency | Supports compound selection |
| Sour Service | H2S, CO2 and project specification | Supports material review |
| Tubular Data | Pipe body and tool joint outside diameters | Confirms sealing and stripping requirements |
| Quality Requirements | Inspection scope and required documents | Defines the quality plan |
| Commercial Information | Quantity and delivery destination | Supports quotation and logistics |
Clear technical information reduces identification errors and prevents delays during production, installation and pressure testing.
Common Packing Element Matching Problems
| Matching Problem | Possible Result | Recommended Check |
| Correct bore but wrong overall height | The packer may not seat, compress or reopen correctly | Compare the packer height with the original design and installation space |
| Same pressure class but different insert structure | Rubber movement and load distribution may change | Verify the insert angle, quantity and spacing |
| Incorrect inner bore contour | The packer may not seal correctly around pipe or tool joints | Compare the complete bore profile rather than only the bore diameter |
| Unsuitable elastomer compound | Rubber may swell, harden, soften or crack | Review fluids, temperature, pressure and chemical exposure |
| Distorted physical sample | Measurements may no longer represent the original product | Compare the sample with drawings, BOP data and installation dimensions |
| Incomplete equipment identification | The supplier may select the wrong replacement design | Provide the exact model, nameplate, part number or verified dimensional data |
A description such as “13-5/8 inch annular packer” or “11 inch 10K rubber element” may not identify the exact product. Verified equipment data remains essential.
Quality Control and Documentation
Each annular BOP packing element passes through elastomer preparation, steel insert inspection, molding, curing and final verification.
| Inspection Stage | Main Check | Available Record |
| Rubber Material Control | Compound identification, batch and storage condition | Batch traceability record |
| Steel Insert Inspection | Profile, dimensions, angle, spacing and surface condition | Dimensional record |
| Molding and Curing | Process temperature, pressure and curing time | Production record |
| Visual Inspection | Cracks, contamination, exposed inserts and bonding defects | Final inspection report |
| Dimensional Inspection | Outside diameter, height, bore profile and insert position | Dimensional report |
| Hardness Check | Elastomer durometer when specified | Hardness test result |
| Rubber Property Testing | Tensile, tear and fluid resistance when required | Rubber property report |
| Product Identification | Model, batch and product marking | Identification record |
| Fit-Up Review | Model-specific dimensional or installation check | Agreed inspection record |
The available document package can include a Certificate of Conformity, dimensional inspection report, rubber property report, batch identification record, product photographs, packing list, agreed manufacturing records, third-party inspection report and manufacturer data record.
The purchase order, technical specification, inspection plan and agreed quality requirements define the final documentation scope.
Customers who need third-party inspection, an MDR or API Monogram documentation should state these requirements before quotation. SGPE will then review the applicable inspection scope, cost and delivery schedule.
A reference to API 16A does not automatically mean that every replacement annular BOP rubber element carries an API Monogram. SGPE confirms certification, testing and documentation separately for each order.
Signs That an Annular BOP Packing Element Needs Replacement
Do not keep a packing element in service only because its outer surface still looks complete.
Replace or investigate the packer when it shows deep cuts, exposed steel inserts, rubber-to-metal separation, permanent bore deformation, excessive swelling, brittle rubber, surface cracking, poor recovery or repeated pressure-test leakage.
Abnormal hydraulic closing pressure may also indicate packer damage, incorrect installation or a problem elsewhere in the annular preventer.
Inspect the packing element after a well control event, difficult pipe stripping, a severe pressure cycle, unusual tool joint passage or abnormal BOP operation.
A failed pressure test does not always mean that the main packer caused the leakage. Inspect the head seals, piston seals, chamber seals, housing surfaces and hydraulic control system at the same time.
Installation, Inspection, Maintenance and Storage
Before installation, inspect the packing element for cuts, cracks, contamination, deformation, exposed inserts and rubber-to-metal separation.
Check the BOP head, piston, housing and internal contact surfaces. Corrosion, sharp edges, dirt or mechanical damage may harm the new packer during installation or its first closing cycle.
Use suitable lifting equipment for large-bore packing elements. Do not use hooks, chains or sharp tools that may cut the rubber.
Apply only lubricant approved for the BOP and elastomer compound. Unknown grease, mineral oil or solvents may attack the rubber.
After installation, complete the required function and pressure tests before returning the annular preventer to service.
During operation, apply only the hydraulic closing pressure required to maintain a stable seal. Excessive pressure increases rubber stress and may shorten service life.
When stripping drill pipe through a closed annular BOP, follow the original equipment procedure and keep the pipe body and tool joint dimensions within the approved range.
Store spare packing elements indoors in a cool, dry and ventilated area. Keep them in their original packaging and protect them from direct sunlight, ozone-producing equipment, welding operations, strong heat, fuels, acids, solvents, drilling chemicals and heavy loads.
Do not place heavy BOP components directly on the elastomer because long-term loading may permanently change its shape.
Related Annular BOP Spare Parts
| Spare Part Category | Available Components |
| Main Packing Components | Annular BOP packing elements and spherical rubber cores |
| Piston and Chamber Seals | Operating piston, opening chamber and closing chamber seals |
| Head and Housing Seals | Head seals and housing seals |
| O-Ring Kits | Model-specific O-ring kits |
| Wear and Support Parts | Wear rings, support rings and adapter rings |
| Dust Protection Parts | Dust rings and wiper seals |
| Operating Components | Operating pistons and selected hydraulic components |
| Structural Parts | Top caps and fastening parts |
| Complete Seal Packages | Complete annular BOP seal kits |
| Overhaul Packages | Complete annular BOP overhaul packages |
Ordering the main packing element together with the required seals and repair parts reduces the risk of missing components during maintenance.
A complete annular BOP seal kit or overhaul package can also shorten equipment downtime and simplify repair planning.
Why Choose SGPE for Annular BOP Packing Elements?
The available range covers FH18, FH28 and FH35 packing elements, spherical and conical packers, tube-shaped rubber elements, NBR and HNBR compounds, high-temperature and sour-service material reviews, complete seal kits and overhaul packages.
Our technical team can identify a replacement from the original part number, BOP nameplate, technical drawing, detailed measurements or physical sample.
Depending on the purchase order, the supply package can include batch identification, dimensional inspection, rubber property reports, product photographs, third-party inspection and protective export packaging.
Instead of selecting a packer from bore size alone, the technical review considers the exact BOP model, internal geometry, pressure class, tubular profiles, drilling fluid and service environment.
Frequently Asked Questions About API 16A Annular BOP Packing Elements
1. What does an API 16A Annular BOP Packing Element do?
It forms the flexible pressure seal inside an annular blowout preventer. Hydraulic force compresses the reinforced rubber toward the bore center, allowing it to seal around drill pipe, tubing, casing, kelly and approved tool profiles.
Buyers may also call it an annular BOP packer, BOP packing unit, rubber element or spherical rubber core. These terms identify the product category, but the original equipment design determines the correct replacement.
2. Can one annular BOP packer fit several pipe sizes?
An annular packer can normally seal around several tubular diameters within its approved range because it closes inward from every direction.
However, its sealing range depends on the preventer model, packer design, tubular profile and operating limits. It cannot replace a ram BOP packer, and it should not handle pipe or tool joints outside the approved size range.
3. What bore sizes and pressure classes are available?
Common bore sizes include 7-1/16, 9, 11, 13-5/8, 16-3/4, 18-3/4, 20-3/4 and 21-1/4 inches.
Typical pressure classes include 2,000, 3,000, 5,000 and 10,000 psi. Selected annular BOP designs may use a 15,000 psi packing element after technical confirmation.
The equipment model and packer geometry remain more important than bore and pressure alone.
4. Which FH packing element models can SGPE review?
SGPE reviews requirements for FH18-21, FH18-35, FH18-70, FH28-35, FH28-70, FH35-35 and FH35-70 spherical packing elements.
FH18 models commonly relate to 7-1/16-inch applications, FH28 models often use an 11-inch bore, and FH35 models commonly serve 13-5/8-inch BOPs. Always confirm the nameplate, pressure class and existing packer dimensions.
5. Can SGPE match a Hydril-type, Shaffer-type or Cameron-type packer?
SGPE can review compatible replacement options for common international annular BOP designs.
The same bore and pressure class do not guarantee a correct fit. The replacement must match the outside profile, height, bore contour, insert arrangement, piston contact surface and elastomer compound.
A compatible replacement does not mean that SGPE acts as the original manufacturer or an authorized representative of the third-party brand.
6. How should I choose between NBR, HNBR and a special compound?
NBR suits many conventional drilling environments and moderate temperatures. HNBR may provide improved mechanical strength and temperature resistance in selected applications.
Special compounds may suit oil-based mud, synthetic fluid, concentrated brine, hydrocarbons, elevated temperatures or project-specific chemicals.
Provide the operating temperature, fluid system, closing frequency and stripping requirements before selecting the elastomer. Hardness alone cannot confirm suitability.
7. Can SGPE review an annular BOP packer for H2S service?
Yes. Provide the H2S and CO2 concentrations, pressure, operating temperature, fluid information and project specification.
A sour-service elastomer only addresses the packing element. It does not qualify the complete BOP for every H2S or NACE-related requirement. The metallic parts, secondary seals, materials and equipment documentation may need separate confirmation.
8. Can the packing element seal an open bore?
Many annular BOP designs allow the packer to close across an empty bore. However, the allowable open-bore pressure may remain below the full rated pressure of the preventer.
The limit depends on the BOP model, packer geometry, hydraulic closing pressure and approved operating procedure. Operators should follow the original equipment limits before relying on open-bore sealing.
9. Can an annular BOP packer support pipe stripping?
Certain packers can seal around tool joints and support controlled pipe stripping.
Provide the drill pipe OD, tool joint OD, well pressure, stripping speed, closing pressure, lubricant requirement and BOP model. Excessive closing pressure, unsuitable lubricant or repeated high-load stripping can damage the elastomer.
10. How can I identify a replacement without a part number?
Start with the BOP manufacturer, exact model, bore size, working pressure and a clear nameplate photograph.
When the part number is unavailable, provide top, bottom and side photographs of the old packer. Include its outside diameter, overall height, inner bore profile, insert quantity and visible markings.
Because a worn sample may swell or deform, compare its measurements with the BOP design and installation space.
11. What can cause an annular BOP pressure-test failure?
Possible causes include worn rubber, deep cuts, swelling, incorrect dimensions, exposed inserts, poor recovery, unsuitable compounds, incorrect closing pressure, damaged contact surfaces or leaking secondary seals.
Inspect the complete preventer before assuming the main rubber element caused the failure. Replace the packer when damage or repeated leakage prevents reliable sealing.
12. What inspection documents and repair parts are available?
The agreed scope may include visual inspection, dimensional verification, hardness testing, batch identification, steel insert inspection and fit-up review.
When required, SGPE can arrange rubber testing according to ASTM D412, ASTM D624, ASTM D2240 and ASTM D471.
Available repair parts include piston seals, head seals, housing seals, chamber seals, O-rings, wear rings, support rings, dust seals and complete annular BOP seal kits.
Request a Quote for API 16A Annular BOP Packing Elements
For accurate identification, provide the BOP manufacturer, exact model, nameplate photograph, nominal bore, working pressure and original part number.
Photos, drawings and dimensions of the existing packing element will help confirm its structure and installation geometry. Useful dimensions include the outside diameter, overall height, inner bore profile and steel insert arrangement.
Please also include the required elastomer compound, operating temperature, drilling or completion fluid, wellbore fluid, pipe and tool joint sizes, H2S or sour-service conditions, quantity, inspection requirements, required documents and delivery destination.
SGPE will review the available information and recommend a suitable replacement packer or complete annular BOP repair package for drilling, workover, completion, well testing or well intervention service.
E-Mail:
info@sgpe.com
