TWO-RISER SYSTEM IMPROVES DRILLING AT AUGER PROSPECT

Romulo Gonzalez, Gary L. Marsh, Paul B. Ritter, Paul E. Mendel
Shell Offshore Inc.
New Orleans

A two-riser system (TRS) for drilling deepwater development wells eliminates some of the limitations of conventional subsea technology and allows flexibility in well programs.

Shell Offshore Inc.'s deep exploratory wells in Garden Banks 426 and 471 have encountered drilling problems that were attributed to limitations in casing sizes imposed by conventional subsea drilling systems. These problems are not uncommon in exploratory deepwater, deep well drilling in the Gulf of Mexico.

Reservoir depths of up to 19,500 ft true vertical depth (TVD) and 7-in. production casing requirements led to potentially troublesome and expensive well plans. Because of the constraints placed on the development drilling program by completion requirements and directional drilling, a two-riser system was designed and fabricated. Solving such significant drilling problems has reduced overall development costs.

The Auger tension leg platform (TLP) is scheduled for installation in 2,862 ft of water in Garden Banks 426 in 1993. The Auger TLP is designed to use proven guidelineless floating drilling technology and to incorporate predrilled wells. The TLP design uses an eight-point mooring system to enable it to be positioned over a predetermined location on the seafloor. Therefore, no subsea template is required, and wells are drilled with individual guidelineless structures and subsea wellhead systems.

To accelerate production, wells are being drilled prior to installation of the TLP. These wells are predrilled from a moored semisubmersible drilling rig in much the same manner as future wells will be drilled from the TLP. All drilled wells will eventually tie back to the TLP through production risers.

Because of the great well depths and production casing needs, preliminary well plans were complex and costly. The depths of the Auger wells range around 15,300-19,500 ft TVD, or 17,000-22,000 ft measured depth (MD). To enhance productivity and completion integrity in these deep wells, they were designed with 7-in. production casing. Preliminary well plans using conventional subsea drilling systems resulted in close clearance casing programs which necessitated deep underreaming in directional hole sections. These types of well plans were known to be problematic in the deepwater Gulf of Mexico environment.

The TRS was developed to establish a larger casing program than allowed by conventional subsea technology. It eliminated many of the close clearance and deep underreaming problems experienced in earlier drilling. The TRS comprises a three wellhead system (36 in. and 28 in. low pressure housings and an 18 3/4 in. high pressure housing), a 26-in. marine riser and 30-in. subsea diverter, and a conventional 21-in. riser and subsea blowout preventer (BOP) stack. The 26-in. riser is used in conjunction with the subsea and surface diverter to drill and case the surface hole while maintaining full hydrostatic control of the well.

A conventional marine riser and BOP system are then used to drill below the surface casing.

DRILLING ENVIRONMENT

The two discovery wells, drilled in 1987-88, found deep reservoirs in a difficult drilling environment. Consequently, many drilling engineering difficulties had to be considered in the design of the development drilling program:

Well structural integrity
Limitations imposed on casing programs by existing subsea wellhead and marine system technology
Troublesome shale intervals
Integration of drilling and completion well systems with the TLP system
The ability to predrill wells with a semisubmersible.

The first exploratory well, Auger 1, was drilled to 16,550 ft followed by two geologic sidetracks to 16,612 ft and 20,760 ft. The second well, Auger 2, was drilled as a directional well to 17,766 ft and had a geologic sidetrack to 20,300 ft. The exploratory wells experienced significant borehole and mechanical problems, including stuck casing, stuck drill pipe, underreaming problems, and high torque and drag (Figs. 1 and 2). Subsequent analysis of log data, sidewall samples, borehole problems, and drilling practices indicated an overpressured and undercompacted massive shale section around 11,000-12,000 ft TVD (Fig. 3).

This troublesome shale section contributed to stuck 11 3/4-in. casing and severe borehole instability problems. As with most shale instability problems, both mud weight and exposure time were key factors. Furthermore, through the interval of 13,500-14,500 ft TVD, stuck drill pipe was caused by differential sticking across underpressured, laminated sand/shale intervals.

A shallow sand zone was penetrated on both exploratory wells approximately 1,106 ft below the seafloor, and it was later determined from seismic to be unavoidable from any potential platform location. Although 20-in. conductor casing was set and cemented through the sand in the second well, the well flowed water, large amounts of silt, and small amounts of gas behind the 20-in. casing and to the seafloor (Fig. 2). This condition was unacceptable in a development program because the continued flow from behind the conductor could undermine the structural integrity of the well and could possibly affect neighboring wells or the tendon foundations on the TLP. Hence, an extra string of casing would be required above the sand on the development wells to preclude potential structural integrity problems.

WELL PLANS

From pore pressure and fracture pressure gradient data obtained from the exploratory wells and with consideration of the borehole-related problem areas, well plans were developed for Auger (Fig. 4). Because of the shallow sand, the low fracture gradients, and the troublesome shale sections, five to six casing strings appeared to be required to reach total depth.

For conventional subsea drilling systems, casing sizes were restricted by the wellhead and subsea BOP dimensions. Conventional procedures required installation of the BOP stack (18 3/4-in. bore) and high pressure wellhead housing (typically, 17.55 in. through bore) at the time conductor casing was run and cemented. Because the BOP stack and high pressure housing are installed for drilling the surface hole, the largest standard size surface casing that could be run was 16 in. This constraint limited the number of casing strings and sizes, led to programs with close casing clearances, resulted in lack of flexibility in planning, and had an adverse effect on well design and depth capabilities.

Well plans developed to use the TRS were estimated to be less costly and troublesome and offered greater flexibility than the conventional well plans. In deep, directionally drilled intervals, an underreamed hole not only requires more time and is therefore more costly, but has significant other disadvantages. The development well plans for use with the two-riser system include the GP-2 and GP-3 (Fig. 4).

Deep directional drilling and underreaming in one pass without a steerable system (bent housing and mud motor) is difficult because bit-sized stabilizers are ineffective in controlling directional tendencies. Therefore, underreaming requires two passes, which leads to longer exposure time in the sensitive shales and possible drilling problems. Also, underreaming can lead to an out-of-gauge hole because of the lack of stabilization or from mechanical problems.

The resulting effective hole size may be similar to that of an unstabilized drilling assembly which results from the difference between the bit and drill collar size (i.e., when underreaming, the difference between the largest stabilizer and underreamer size).1 Underreammed hole sections also require concentric casing strings with close clearances; for example, 11 3/4-in. OD inside 13 3/8-in. casing which has a 12.347-in. ID. In directional holes, a cuttings bed may form on the low side of the casing, thus, limiting the available clearance and potentially leading to stuck casing.

For wells designed with the TRS, no underreaming was required across the troublesome shale section and, therefore, the 11 3/4-in. hole could be drilled much deeper, to 13,500 ft MD. To date, the 11 3/4-in. section has been drilled to a maximum of 14,710 ft MD. Most wells in the development are approximately 21,000 ft MD, and the larger clearances reduce surge pressures while running casing and friction pressures during cementing.

Deep directional wells drilled with conventional subsea drilling technology would be costly and troublesome because underreaming would be required in every section. Also, the close clearance casing programs would lead to high surge pressures while running casing and loss of returns while cementing (i.e., poor cement jobs). It was also estimated that the deeper wells (greater than 21,000 ft MD) may not have been possible with conventional subsea technology.

TWO-RISER SYSTEM

The TRS design predominantly included existing and proven equipment, or, when needed, equipment designed as similar as possible to existing equipment. This provided a high degree of confidence in the system with minimal trouble while keeping design and fabrication times within project schedules.

The 36-in. structural casing is jetted in place, typical to floating operations. The 36-in. housing is modified to allow landing of a 28-in. housing in the internal profile. After jetting the structural casing, a 31 1/2-in. hole is drilled to approximately 1,100 ft below the mud line while taking returns to the seafloor. A remotely operated vehicle (ROV) monitors the well during drilling.

A 26-in. conductor casing string is run on the 28-in. housing and cemented back to the seafloor. The 28-in. housing has the same internal profile as a standard 30-in. housing, allowing use of a standard running tool. A standard hydraulic pin connector can later be used for latching the subsea diverter system and large riser. Also run on the conductor casing is a 28-in. adaptor sub which provides a load shoulder and seal area for the 20-in. surface casing hanger.

After cementing the 26-in. conductor casing, a subsea diverter system assembly (SSDA) and 26-in. riser are run, and the hydraulic pin connector is used to latch to the 28-in. housing (Fig. 5). A surface diverter system is also made up to divert gas that may inadvertently enter the riser.

The surface diverter, subsea diverter, and riser are designed for drilling the surface hole and for running and cementing the 20-in. surface casing. The 26-in. riser does not have choke kill, or mud boost lines. The riser is purposely built for the particular mud weights needed to drill the surface hole at Auger.

The surface hole is drilled and 20-in. surface casing run and landed in the 28-in. adaptor similar to conventional subsea casing hangers. The surface casing is then cemented, and a subsea seal assembly is set in the 28-in. adaptor and tested. After cementing and testing the 20-in. casing and seal assembly, a heavy mud pill is spotted in the casing, and the riser is displaced with seawater and retrieved.

The 18 3/4-in. high pressure housing assembly is run in open water and separate from the 20-in. surface casing (Fig. 6). The 18 3/4-in. housing is attached to a 20-in. stab sub which seals into a tie-back receptacle at the top of the 20-in. casing. The assembly is then pressure tested. To provide a load transfer mechanism, the wellhead is then rigidly locked in place to the 28-in. housing.

A conventional 18 3/4-in. 10,000-psi subsea BOP stack and 21-in. marine riser are run and latched to the 18 3/4-in. housing. The remaining drilling operations below the 20-in. surface casing are typical to conventional subsea drilling.

For greater efficiency in riser handling and operating, the wells are "batch-set" to the surface casing point.

The SSDA/26-in. riser or the conventional stack/21-in. riser can be moved from one well to the next, thereby saving the time otherwise required for running and retrieving each riser alternately and between wells.
Operational efficiencies are gained by performing the same task repeatedly.
Logistics are simplified by eliminating frequent loading and off-loading of risers on the rig to prevent overloading it with both.

SURFACE HOLE SAFETY

A number of surveys showed that the area was free of shallow hazards. However, in the unlikely event of a strong well flow, gas can be kept away from rig personnel while minimizing the potential for broaching the conductor casing. The subsea diverter can divert gas near the seafloor, thus preventing gas from continually entering the riser and potentially damaging the surface diverter.

Any gas that may have entered the riser prior to shutting in the subsea diverter can be kept away by the surface diverter. Gas surfacing at sea level is not expected to be an ignition source or to cause stability problems to a semisubmersible or TLP in 2,862 ft of water.2 3

A dynamic kill while diverting subsea can then be conducted with assistance from the hydrostatic head of the seawater column.

In general, the approach to well control is to use the surface diverter to divert limited amounts of gas (such as swabbed gas or drilled shows) that may enter the riser. If mud becomes gas cut, mud weight is adjusted while circulating through a high-volume riser mud/gas separator with the surface diverter packer closed (Fig. 7).

In this mode, circulation is basically the same as that used on jack ups and fixed platforms with only one diverter (at surface). However, the mud/gas separator is optionally available between the diverter housing and the overboard lines to recover the mud.

If gas cutting threatens to unload the riser, the subsea diverter would be closed, thereby diverting the excessive gas just above the seafloor. Subsea diverting of shallow gas will greatly reduce the possibility of broaching the conductor casing and of damaging the soil near neighboring wells or the TLP tendons. Fracture pressures at the conductor setting depth are very low; hence, a conventional approach of shutting in the well would likely lead to fracturing (Fig. 3). For diverting subsea, the maximum pressure at the shoe is controlled in a large measure by the constant hydrostatic pressure of seawater at the diverter outlets and is not likely to be high enough to fracture the well (Fig. 7).

Many well control failures have resulted from surface diverter failures and from gas flows after cementing casings.4 With the TRS, the 20-in. seal assembly seals off the surface casing annulus immediately after cementing, reducing the possibility of an annular gas flow. Because significant flows are diverted subsea, the surface diverter system will not be subjected to high dynamic loads, high pressure loads, or erosive effects.

SUBSEA WELLHEAD SYSTEM

The subsea wellhead system allows guidelineless re-entry operations, has 10,000-psi high pressure components, and transfers drilling and production riser loads through the 18 3/4-in. and 28-in. wellhead housings to the 36-in. wellhead housing and structural pile.

The well system is designed to be as ROV "friendly" as possible. ROV visual inspections verify that subsea equipment is positioned and functions properly. For example, the operation of the rigid lock down tool, which locks the 18 3/4-in. housing to the wellhead, is monitored for position. The ROV uses clearly marked references and visual ports in the guide funnel to watch the operation. Components such as the 30-in. hydraulic pin connector, the rigid lock down tool, and future interfacing components for installing production risers have or will have ROV interfaces for hydraulic fluid overrides.

Finite element analyses were performed on the wellhead system to determine the fatigue characteristics. Initial design modifications to the wellhead system were based in part on these analyses. An ASTM A707 alloy material was used for fabrication of the wellhead housings and certain components of the 26-in. and the 20-in. casings. The A707 was specifically selected because of its strength characteristics and its resistance to fatigue crack propagation in the cold seawater environment (4 C. at 3,000 ft). It is conservatively estimated that the wellhead system far exceeds the specified 350-year fatigue life.

Several prototype components were fabricated for the TRS wellhead system, including the 36-in. and 28-in. wellhead housings and the 20-in. seal assembly casing hanger systems. The procedure of running the 18 3/4-in. wellhead assembly separate from the conductor casing is a unique process and required prototype equipment.

To qualify the designs of the newly developed equipment, rigorous design qualification test (DQT) procedures were performed. The tests fully evaluated the functional performance of the various equipment and tools under conditions that closely simulated each specific application. DQTs were conducted to qualify the rigid lock down feature of the 18 3/4-in. high pressure wellhead housing, the 20-in. seal assembly and casing hanger, the 20-in. stab sub, the prototype running tools, and other equipment needed for installation of casings and production risers.

The rigid lock down mechanism and the running tool were tested to verify a successful lock down inside the 28-in. wellhead housing. The lock down was tested to 400,000 lb tension. The 20-in. seal assembly and the 20-in. stab sub were gas tested under pressure and thermal cycle iterations that simulated anticipated producing well conditions. Also, the 20-in. stab sub underwent rigorous testing by subjecting the seals to harsh friction and drag tests to simulate open water installation.

Operations were conducted in a test tank to evaluate underwater ROV interfaces and to function test the prototype equipment in an underwater environment. The program tested a series of paint schemes to determine which offered the most desirable underwater visual characteristics.

Every component of the wellhead equipment is designed to be interchangeable. To minimize potential fit problems during the installations, every set of Auger marine wellhead equipment is fit and function tested before going to the field. Each well component is placed in a color-coded set after the function tests. From this point on, each matched set is designated as a specific unit and is kept together as the well installation proceeds.

DIVERTER ASSEMBLY

The subsea diverter assembly (SSDA) is a fully framed, guidelineless subsea stack 27 ft high and 18 ft x 14 ft at the widest cross section. The system weighs 145,000 lb and has a working pressure of 1,000 psi.

From top down, its basic components include: 26-in. riser adaptor; 30-in. flex joint; 30-in. annular BOP; 30-in. drilling spool with two 12-in. hydraulic-operated, ball-type diverter valves; and a 30-in. hydraulic pin connector which locks down and seals to the 28-in. wellhead housing. Dual subsea control pods for the 18 3/4-in. subsea BOP are also used to control the SSDA. The pods can convert for SSDA use simply by manipulation of several hand valves.

Both the annular and system regulators are thereby enabled to obtain control fluid at a rate sufficient for 45-sec closure of the large annular BOP, which requires 118 gal. Most of the power fluid comes from SSDA-mounted subsea accumulators charged from the 1-in. supply line in the active subsea control hose bundle. There is no rigid conduit on the 26-in. riser.

MARINE DRILLING RISER

The subsea diverter is deployed on a special 26-in. marine drilling riser furnished in 60-ft lengths. This riser has no externally mounted lines. Choke and kill tines are not needed because of the subsea diverting capability, and a riser boost line is not needed because the drilled hole size approximates the riser bore.

The 26-in. riser is much like the 21-in. riser used with the 18 3/4-in. BOP, that is, made rugged and heavy duty for deep water critical service. Riser connections are 26-in. nominal flange-type APT Class "D" (1.5 million lb) with flanges secured by six axial bolts. The tube is 26-in. nominal, 5/8-in. wall APT X-80 line pipe, rolled and welded. More than half of the 2,860-ft deployed riser will have foam flotation for near-neutral buoyancy.

The 26-in. and 21-in. risers share several common components: bolts, bolt wrenching equipment, spider, gimbal, and crane pick up tools. Both can be handled from rack to V-door with the same handler preparations. Floor handling tools are different because of the difference in bore. An hydraulic handling tool that engages grooves on the box ID has been used very successfully to date.

The 26-in. riser design criteria were 10 ppg mud weight and 1,500 ft of evacuation. Total evacuation criteria were judged unnecessary because the bottom of the riser will be at seawater hydrostatic pressure as soon as the subsea diverter valves open. Then the riser will be isolated from the well once the subsea diverter packer has closed. Tension and flotation design were governed by the 1,000,000-lb capacity tensioner system of the TLP and the known rigors of deepwater drilling. Another critical factor in design was the need to operate in proximity to the array of TLP wells.

PERFORMANCE

The SSDA annular preventer had problems with adequate closure early in the predrill program. An adverse pressure/area relationship was found in the particular BOP chosen. The BOP was harder to close with the bore exposed to 2,860 ft of hydrostatic mud head in the riser than at the surface.

Certain subsea accumulators are now dedicated to final closure of the annular element through a separate pod function which is triggered sequentially after the primary accumulators are mostly discharged. Since the addition of the dedicated accumulators and the sequenced function, the SSDA has functioned satisfactorily during the predrill operations.

Nine wells have been spudded and had operations completed through the 20-in. surface casing point. Three wells have been drilled to total depth, cased, and temporarily abandoned.

Two minor wellhead system problems developed early in the program. The first occurred during installation of the 18 3/4-in. wellhead assembly. Gumbo clay deposits on the inner walls of the well equipment prevented the 20-in. stab sub from fully engaging. The assembly was brought back to the surface and successfully rerun with additional drillstring weight. The stab sub was then modified to include increased flow-by areas, and no further problems have occurred.

The second problem was caused by interference between the guide shroud on the SSDA and the guide base. The problem was corrected by small dimensional adjustments to the guide shroud.

The batch setting process has led to exceptional performance because of a learning curve impact in drilling through the surface hole (Fig. 8). No significant well control problems occurred in the drilling of the surface casings. Therefore, no data are available on the performance of the subsea diverter except for weekly tests and functioning to set or test seal assemblies.

The development wells had no problems during drilling through the shale section that was questionable in the exploratory program. Performance on the overall drilling is significantly better than the performance in the exploratory wells, even if the trouble events are not considered in the latter. Overall, drilling performance of the development wells has exceeded expectations.

To date no well control incidents have required subsea diversion; however, industry experience suggests subsea diversion to be an effective and safe operation.

REFERENCES

Lubinski, A., and Woods, H.B,, "Factors Affecting the Angle of Inclination and Dog-legging in Rotary Boreholes," API Drilling and Production Practice, pp. 222-42, 1953.
Milgram, J., and Erb, P,R., "How Floaters Respond to Subsea Blowouts," Petroleum Engineer, June 1984.
Adams, N., and Kuhlman, L.G., "How to Prevent or Minimize Shallow Gas Blowouts," World Oil, May 1991.