Robert E. Sokoll, Carl W. Sauer, William G. Kelly
Conoco Norway Inc.
Stavanger
A highly iterative and complex process is needed to determine the optimal size and type of subsea wellhead equipment needed for tension leg platform (TLP) production operations.
The process includes information from drilling, topsides, and associated well systems engineers.
Subsea wellhead systems provide the foundation for production operations from a TLP. Because the subsea wellhead reduces the loading on the TLP, the only weight that the TLP must support is the drilling riser, production risers, and upper part of the completion string (Fig. 1).
The size of the subsea wellhead equipment and associated riser equipment will impact template and TLP designs as well as the auxiliary equipment to support the riser systems.
Larger-diameter drilling riser equipment will require large tensioning equipment capacity and large hatch openings for equipment passage, and it potentially can affect wellhead spacing on the seabed or template due to riser motions and interference concerns during deployment.
TLP operations can use three different internal diameter subsea wellhead systems: 21 1/4, 18 3/4, and 16 3/4 in. The types of drilling riser equipment and wellhead sizes are listed in Table 1.
Several drilling and production factors must be considered when selecting subsea wellhead equipment for TLP use. These factors include:
- Reservoir and well completion requirements
- Well bore profiles
- Borehole stability
- Maximum anticipated surface and subsea wellhead pressures
- Riser and riser component design
- Development plans
- Production riser tieback connector
- Cathodic protection
- Materials selection.
The flow chart (Fig. 2) indicates the major considerations for selection of TLP subsea wellhead equipment.
RESERVOIR AND COMPLETIONS
Reservoir areal extent, depth, and production potential are critical factors in determining the required production casing size and number of casing strings that will have to be set.
Factors for determining the maximum well bore deviation angle to drill include areal extent of the reservoir, depth of the reservoir, completion considerations, and the water depth. Deviation angle will influence the required minimum mud weight to maintain borehole stability.
The expected production rate will determine tubing size that will affect the production casing size.
For example, expected production flow rates may require a 7 or 5 1/2-in. tubing completion. The tubing size could dictate that 9 5/8-in. production casing be set.
Other completion philosophies such as sand production tendencies, the use of downhole pressure gauges, tubing hang offs, and the use of annular safety valves will affect drilling and completion strategies.
Because of this, the casing string sizes should be determined very early in the project stage because their sizes will affect wellhead preload values.
Failure to design the well bore casing program early could result in nonoptimized preload values and impact running tool equipment size and pressure requirements.
Other completion philosophies such as downhole safety valve type, downhole pressure gauges, and tubing hang off will also affect drilling and completion strategies and dictate the dimensions of the upper part of the production casing and the casing hanger design for the subsea wellhead.
Wells drilled in deep water may require sand control to economically produce the well. Sand formations exhibiting high porosity and permeability can produce in excess of 30,000 bo/d.
For wells with gravel packs to control sand production, inflow curves should be used to determine the optimum tubing and casing size required to produce the well at peak production.
Because of large perforation diameter as well as increased perforation efficiency, from a production rate standpoint, it is advantageous to complete wells with inside casing gravel packs in 9 5/8-in. casing instead 7-in. casing. A production rate comparison can be seen in Fig. 3. Other justifications for larger casing include:
- The ability to run the full spectrum of production logs
- Lower flow velocities to avoid erosion
- Increased chances for successful workovers.
Anticipated production temperature profiles should also be calculated as part of the preliminary work. These temperatures should be based on peak production rates and water cuts.
The reduction of effective casing weight due to temperature increases will impact the wellhead preload value and must be accounted for in both conductor and high-pressure housing designs. Temperature profiles will also be required to determine 30-in. casing growth and any resultant impact on the wellhead template as a result of increased production temperatures.
WELL BORE PROFILES
To reach TD, the deviation of the wells drilled from TLP and production casing requirements may force setting an intermediate casing string such as 16 in.
An alternative to setting a 16-in. casing string is to set an 11 3/4-in. drilling liner. Both options would require under-reaming for that casing string and the subsequent casing string.
An 11 3/4-in. liner will require extra rig time to test the liner lap and drill out cement. The use of 16 3/4-in. wellhead equipment would eliminate the possibility of setting a 16-in. casing string and require that a 11 3/4-in. liner be used instead.
Flush-joint 9 5/8-in. casing would be needed to pass through the 11 3/4-in. liner. If the 9 5/8-in. casing is required for completion equipment, obtaining a good hydraulic seal across the production zones with the cement job may be difficult.
Therefore, one must consider the ultimate casing program to successfully reach TD prior to the final selection of wellhead size.
BOREHOLE STABILITY
Borehole stability1 2 can create problems in keeping the drilled hole open in deviated wells.
Borehole stability is a function of hole deviation, casing seat fracture gradients, local tectonic stresses, and mud weight.
As hole deviation increases, additional mud weight may be required to keep the borehole from collapsing due to overburden stresses.
Borehole stability calculations should be done to determine the number of casing strings that have to be set in the well.
A borehole stability curve (Fig. 4) was calculated for the Kearney plot shown.
The 60 hole angle stability curve indicates that an intermediate 16-in. casing string may be required to successfully reach the production objective of setting 9 5/8-in. casing through the production zone.
PRESSURE REQUIREMENTS
Pressures that wellhead and drilling riser equipment could potentially be exposed to should be determined. For pressure calculations, reference depths should be the subsea wellhead and surface blowout presenter (BOP) stack.
The calculations include pressures to control formation fluids and also the imposed pressures such as for testing casing, testing tubing, or functioning drillstem test (DST) equipment.
Kearney plots (Fig. 5) are useful in determining maximum anticipated pressures at surface, casing seat, and wellhead datum depths. Eight offset wells were used to construct the Kearney plot in Fig. 5.
The DST data are for gas gradient determination.
Maximum surface and wellhead pressures were based on a full column of gas. Based on these pressures and pressures that casing shoes can withstand during drilling, a maximum anticipated surface pressure can be determined.
Fig. 5 shows that a maximum surface pressure of 3,565 psi and subsea wellhead pressure of 3,580 psi are expected assuming 16-in. casing was set. Pressures shown along Line D are higher but would not be seen at surface because the 16-in. shoe (if set) or 20-in. shoe would break down during the drilling operations for setting 13 3/8-in. casing in the pressure reversal.
Based on the expected surface and subsea wellhead pressures, the drilling riser and wellhead equipment working, test, and operating pressures can be determined. These pressure determinations will ultimately provide the well control equipment pressure rating and therefore, the size and weight of this equipment.
The weight of the surface BOP stack in combination with the drilling riser test pressure design criteria will also determine drilling-riser tensioning equipment requirements.
RISERS
Often a TLP uses a surface BOP stack and a high-pressure drilling riser for drilling and completion operations. The drilling riser acts as a conduit from the subsea wellhead equipment to the TLP for drill cuttings return and pressure control.
As the wellhead size increases, the size and weight of wellhead connectors, flexjoint equipment, drilling riser connectors, and drilling riser will also increase.
The size of the riser will have a direct impact on template wellhead spacing, riser tensioning equipment, and TLP deck hatch opening through which all equipment must pass.
Equipment size also relates to the size of surface handling equipment and ultimately enters into the equation for determining the displacement volume of the TLP hull.
For the worst case scenario, the drilling riser should be designed to handle a drilling kick with a full column of gas to surface.
In addition, casing and well control equipment pressure testing requirements should be considered. TLPs that are in deep water complicate casing pressure testing. Hydrostatic pressure in the drilling riser due to different internal and external fluids should be considered when pressure testing casing strings (Fig. 6).
If the differential fluid pressure in the riser is neglected, the drilling riser could accidentally be pressured above the rated working pressure. Worst case burst pressures will be seen immediately below the BOP stack. Reference depth for testing casing should be the subsea wellhead.
If casing is tested to 4,000 psi with a 15 ppg mud, applied surface pressure should be 3,490 psi. Assumed water depth for this example is 1,148.29 ft, and the air gap is 164 ft.
Most API wellhead equipment is standardized with respect to working pressure, e.g., 5,000, 10,000, 15,000 psi, etc.3 Drilling riser equipment design is optimized for the design requirements for the specific TLP application. As a result, it may be possible to have drilling riser working and test pressures that are lower than the API-rated wellhead equipment. This possibility must be accounted for in operational procedures.
Based on the maximum anticipated surface pressure (3,565 psi) and applied surface pressure during casing testing (3,490 psi with seawater in the riser) presented here, the drilling riser could be rated for a working pressure of 4,000 psi.
Failure to optimize on the pressure rating for the drilling riser can result in paying dividends on well spacing to avoid collisions between the drilling riser and surrounding production risers.
The drilling riser tensioning equipment should be capable of handling the weight of the surface BOP and drilling riser with internal pressure in the riser.
The combined loading of tension and internal riser pressure load should consider the end cap effect of the drilling riser with an acceptance test pressure applied.
Assuming a 22 1/2-in. internal diameter riser with an acceptance test pressure of 7,500 psi, the equivalent end cap load is 2,982,058 lb.
During riser analysis, it may be found that tensioner and pressure loading of the riser may exceed the allowable end cap load. This problem can be handled operationally when the drilling riser is in use.
When pressure is applied internally to the riser, it will expand the riser in length resulting in a net decrease in the riser weight (Fig. 7). Loading that tensioner equipment must compensate for can be reduced to decrease the combined loading of the drilling riser.
The drilling riser can be retensioned as the applied pressure is bled off. Another way to reduce drilling riser dry weight and then tensioner and support structure requirements is by using alternate materials such as titanium instead of steel.
For risers with similar performance specifications, titanium, being lighter and stronger than carbon steels, will reduce the required wall thickness and weight of the drilling riser.
A thorough drilling and production riser motion analysis should be completed to determine any riser interference problems.
Production and drilling risers may bounce into other risers depending on ocean criteria, vessel motion characteristics, and wellhead spacing at the template or well bay.
Wellhead spacing can be increased to eliminate potential riser interference but could impact TLP structural design or the number of wells that can be effectively drilled and produced from the TLP.
It is imperative that these analyses not only consider in place analysis but also consider riser deployment scenarios. Normally the analysis is an iterative process that may require three or more cycles from conceptual through final design.
Riser, riser tensioning, and subsea guidance equipment will have to pass through various TLP deck levels. Hatch opening sizes will be dictated by the size of riser components, type of guidance equipment used for the subsea wellhead equipment, and guidepost spacing requirements.
Riser equipment that must pass through the hatches includes wellhead connectors, lower marine riser packages, flex-joint equipment, riser connectors, riser buoyancy elements, production tie-back systems, and production riser tensioner systems.
Wellhead connectors and lower marine riser packages (if run) will generally be the component with the largest outer diameter that must be run on the riser followed by the flex joint.
Wellhead connectors range in size from 47 to 69 in. depending on pressure ratings and the manufacturer supplying the connectors.
Rotary table size or the need to remove it or component parts could be influenced by the connector size if the rotary table cannot be stored on the BOP deck level when not in use.
However, the production riser tie-back connector is run with a stress or taper joint and generally run through the rotary table.
A drilling riser booster line may be beneficial, and its inclusion in the drilling riser design will be dependent on the smallest hole size that will be drilled, mud weight, and size of the drilling riser. Annular velocity in the drilling riser may not be high enough when drilling small diameter boreholes to remove drilled cuttings from the well bore.
Metal cuttings from milling operations would also be difficult to remove from the well in larger annuluses. Heavier muds will help carry drilled cuttings from the well bore, unlike low weight muds or clear completion fluids. Based on drill pipe annular velocities, different drilling riser sizes should be calculated for various flow rates.
Annular velocities in the drilling riser will be operator dependent. An annular velocity of 72 fpm was deemed adequate for the Heidrun TLP high-pressure drilling riser with an internal diameter of 22 1/2 in.
Expected booster-line, pressure-loss calculations using expected mud weights should also be performed to determine minimum line size and booster pump sizing and pressure rating (Figs. 8 and 9).
From these calculations the booster line can be sized. First, this size must be checked for compatibility with drilling riser connector designs. Then the resulting OD needs to be checked to see if the drilling riser can still be run through the rotary table.
Drilling and completion tool passage through the drilling riser, flex joint, stress joint,
and wellhead equipment should be considered. Subsea wellhead equipment running tools may have difficulty passing through the flex joint dependent on the flex-joint angle.
On the other hand, a stress joint will bend slightly, but the angular displacement is gradual instead of an immediate angle change inherent with flex joints. As a result, tool passage is accomplished easier through stress joints than through flex joints.
Of course, should a stress joint be used then the wellhead connector and subsea wellhead must be checked to ascertain if the design can withstand the increased loading imposed through a stress joint as compared to a flex joint.
Minimum ID through the wellhead, normally the shoulder used to support the first landed casing hanger, must also be considered. This ID may require special ODs on tools or casing connectors to successfully achieve the goals set out in the casing program.
Guidance equipment used for the subsea wellhead systems could also impact TLP deck hatch openings. Standard API guidepost centerline spacing is 6 ft from wellhead center.4 This spacing can be modified if required for TLP design requirements.
Hatch openings should be large enough to pass funnelled guidance equipment that will be larger than the guidepost spacing due to funnels on the guidance frame.
Guidelineless equipment will require that the TLP can be moved and kept stationary above subsea wellhead equipment. This will increase the subsea wellhead spacing on the seabed and most likely preclude template structures.
Guidelineless systems will be affected by ocean currents, and lateral movement is not constrained as guidelines are not used. Therefore, greater wellhead spacing will be required to control production and drilling riser interferences. This will also impact TLP drilling rig design.
DEVELOPMENT PLANS
Predrilled TLP production wells are simplified, and standard subsea drilling equipment and techniques can be used. Subsea BOP equipment up to 21 1/4 in. size is available.
To avoid any subsea BOP stack guidance modifications, predrilled wells should use standard API guidepost spacing for subsea systems with guideline equipment. Subsea BOP equipment could be modified for non-API spacing but that is considered to be cost prohibitive. Guideline tensioning equipment spacing would also have to be modified.
Predrilled wells should be capable of being worked over using TLP drilling riser equipment. This could impact subsea wellhead size selection. For example, predrilled wells using 18 3/4-in. equipment could not be worked over if 16 3/4-in. wellhead and riser equipment is used for TLP drilled wells.
Difficulty could be experienced should a subsea casing hanger and casing need replacing with the 16 3/4-in., high-pressure riser in place. Therefore, one must always consider what operations may come up later in the life of the field and check that against the selected design.
PRODUCTION RISER
The production riser tieback connector will most likely be the same size and pressure rating as the drilling riser wellhead connector. When combined with guidance equipment, the tieback connector could impact TLP deck hatch opening size and potentially the wellhead spacing on the template.
An option to reducing the OD of the tie-back connector is to use an internal connecting connector instead of the more common external connection on the subsea wellhead equipment. This may not be possible with 16 3/4-in. subsea wellhead equipment.
Other tie-back connector considerations are internal subsea wellhead seal stabs, lockdown mechanisms, ring gasket testing, and ROV pressure monitoring requirements (Fig. 10).
The seal stab acts as an additional pressure barrier to the wellhead ring gasket. The use of seal stabs on the tieback riser connector may eliminate internally connected tie-back connectors.
CATHODIC PROTECTION
Cathodic protection of the subsea wellhead should be investigated during the initial design stages of subsea wellhead equipment being considered for TLP applications.5 Electrical contact between subsea wellhead equipment and wellhead template may not be adequate for the template cathodic protection system to protect the subsea wellhead equipment.
Coatings and sacrificial anodes placed on the uncemented portion of conductor casing above the mudline should be considered for protecting subsea wellhead equipment that may be temporarily abandoned prior to completing the well and running the production riser.
Sacrificial anodes placed on the uncemented portion of the conductor casing will also protect high-pressure subsea wellhead housings due to the high-pressure housing being preloaded to the 30 in. or conductor casing wellhead housing.
After the completed well has been tied-back to the TLP, consideration should be given to strapping the production riser tie-back connector to the template. This will allow the template cathodic protection system to protect the well system.
Coating systems should be evaluated to ensure that the coating does not electrically insulate material from the cathodic protection system. Bolt failures have occurred when exposed coating systems failed because the bolt was electrically insulated leading to the bolt corroding.
MATERIAL SELECTION
Bolting material used on the production tie-back connector and drilling riser wellhead connector must also be evaluated. High strength bolts with cadmium plates have been found to break due to hydrogen embrittlement caused by the plating process.6
Depending on bolting hardness (Rockwell or Birnell scale), bolts may not require any cathodic protection or electroplating.
Extreme care should be exercised when selecting bolting materials for subsea applications. In addition to exposure from external fluid contact, produced well bore fluids may be corrosive, and materials in the subsea wellhead equipment that will be exposed to the produced fluids should be selected carefully. To protect against CO2 corrosion, alloys such as F6NM and duplex materials may be required.
Produced fluids that contain H2S may require that low-carbon materials be used. Hardness (Rockwell) of the material may have to be controlled to prevent hydrogen embrittlement problems.
ACKNOWLEDGMENT
The authors wish to express their appreciation to Conoco Norway Inc., Den norske stats oljeselskap A/S, Norsk Hydro Produksjon A/S, Det Norsk Oljeselskap A/S, and Neste Petroleum A/S for permission to present this article.
REFERENCES
- Fuh, Giin-Fa, "Preliminary Mud Weight Design For The ERDP Well Based On Borehole Stability Analysis," Conoco Inc. Research Report, September 1988.
- Fuh, Giin-Fa, "Borehole Stability Analysis For The Heidrun TLP Wells," Conoco Inc. Technical Service Report, August 1989.
- API Specification 6A, "Specification For Wellhead And Christmas Tree Equipment," 16th Edition, Oct, 1, 1989.
- API Specification 17D, "Specification For Subsea Wellhead, Mudline And Christmas Tree Equipment," Draft, May 1, 1991.
- Thomason, William H., "Comments On Specification For The Design Of Cathodic Protection For The Heidrun Well Template," Conoco Inc. Technical Service Report, April 1991.
- Joosten, M.W., Kiefer, J.H., Wolfe, L.H., Pugh, T.L. and Salama, M.M., "Evaluation Of Detailed Wellhead Studies For The Heidrun TLP," Conoco Inc. Technical Service Report, May 1991.
Copyright 1991 Oil & Gas Journal. All Rights Reserved.
