NORTH SEA HPHT WELLS REQUIRE CHANGES IN DRILLING PROCEDURES

Henrik Bailer
Consultant
Tananger, Norway

Such equipment as casing, drillstrings, mud, logging, and rigs that were adequate to drill most of the North Sea wells to date will require modifications to drill the high-pressure, high-temperature (HPHT) formations in the Central Graben of the North Sea.

HPHT exploration wells are slowly becoming part of the drilling scenario in the North Sea Central Graben (Fig. 1). Predominantly drilled in the U.K., an increasing number are now planned for the Norwegian sector during 1991.

CENTRAL GRABEN RESERVOIRS

The emphasis of hydrocarbon exploration in the Norwegian Central Graben has shifted from medium deep chalk and upper Jurassic to deep overpressured Jurassic plays. Some interesting discoveries have contained oil with associated gas or gas/condensate.

Reservoir pressures of 980 bar (14,200 psi) have been encountered in sands of Jurassic[Triassic age and may reach 1,035 bar (15,000 psi) or more in ultrahigh-pressure wells.

The Norwegian Central Graben deep Jurassic, high-pressure play is located south of the 57th parallel and extends into the U.K. and Danish sectors. Water depth is 60-80 m (200-260 ft).

Well total depths are projected down to more than 5,000 m.

Mud weight required to control pore pressures of a 1,000 bar or more will have a specific gravity of at least 2.20 (18.3 ppg). Expected formation breakdown is in the 2.25-2.30 sp gr range leaving narrow room for safety margins and contingencies.

Aquathermal pressuring is considered to be the prime mechanism of overpressure in deep Central Graben.

Estimated aquifer overpressure is about 550 bar for the ultra-HPHT wells.

For predicting pressure, temperature trends are considered to be more reliable than the conventional d-exponent technique. In the Central Graben, the d-exponent has consistently been in error by up to 200 bars in both the U.K. and the Norwegian sectors.

For deep ultra-HPHT wells, reservoir temperatures of 200 C. (392 F.) plus have been predicted. These high bottom hole temperatures will result in flowing wellhead temperatures of 120-150 C.

Sour gas has been registered at random in deeper Central Graben wells. The gas has not been found in significant amounts nor in a mapable pattern.

For HPHT wells, even small amounts of H2S will exceed the threshold value of 0.05 psi partial pressure as established by NACE (National Association of Corrosion Engineers). For a 13,000 psi wellhead pressure, the threshold value corresponds to 3.85 ppm, an amount hardly detectable. Therefore, the upper part of the deeper casing strings must be designed for sour-gas service.

Correlation between drilled and prognosed HPHT wells indicates common trends for lithology, pressure, and temperature.

CASING DESIGN

The marine conductor and the conductor string follow standard design criteria. The surface, the high-pressure (HP) intermediate, and the production string each have to be designed for a worst case scenario.

The worst case is when casing is fully evacuated to gas. This results in a maximum shut-in wellhead pressure of almost 900 bar (13,000 psi).

This design criteria combined with sour-gas service and strength degrading caused by high temperature has led to the use of high-collapse, heavy-wall casing grades with premium couplings.

For collapse, the casing design needs to include a full mud column behind the pipe in the annulus and a hydrostatic thief zone at TD. The thief zone is expected to partially empty the casing. Furthermore, the gas flow is considered too erratic to use for hydrostatic-head computations.

For burst, the casing design assumes formation pressure behind the pipe. This differentiation between mud column pressure and pore pressure will provide the most severe case for collapse and for burst.

In addition, the 7-in. liner and tie-back string design for near-surface, tubing-leak burst pressure results in a differential pressure across the test packer of around 1,800 bar (26,000 psi).

An ultra-HPHT casing program is shown in Fig 2.

The 14-in. surface string at 2,800 m will case off the presumably weak Balder formation before entering the upper Cretaceous (KU). A 14-in. casing is used rather than 13 3/8-in. because of collapse and clearance requirements.

The 10 3/4-in. HP intermediate string at 4,800 m will case off upper (KU) and lower Cretaceous (KL) before entering the reservoir. The casing seat is planned for the Cromer Knoll (cap rock) or, if drilling conditions permit, in the deeper Mandal (JU) formation.

However, this is questionable since Mandal is an overpressured shale, which may require a dedicated liner. A full string of 9 5/8 in. would fail on the combined requirements to burst and sour-gas service.

Formation breakdown could be anticipated when cementing the 7-in. string, and the drift diameter would be too small to allow the use of 8 1/2-in. metal-seal drill bits for high temperature (HT) service.

At the bottom of the 10 3/4 in., a 300 m section should be run. This section should have an ID that ensures a reliable seal for the RTTS (retrievable test/treat/squeeze tool) and the liner hanger. The ID of the heavy top section has to be considered. The difference in ID between the top and the bottom section should not exceed 3/8 in.

The alternative, a tapered string of 10 3/4 in. and 9 5/8 in. offers few if any advantages compared to the full 10 3/4-in. string. The weight saving is marginal, around 40 tons in mud.

The 7 5/8-in. contingency liner will case off the Mandal formation if hole conditions so dictate.

The 7 5/8-in. liner should be set as deep as possible in case unexpected pressure zones at deeper depths are to be tested. For this reason, sufficient 7 5/8-in. liner should be acquired to run to total depth, at least on the first exploration well.

Two options are offered for the production string to be set at TD (5,000 m plus):

Without a 7 5/8-in. contingency liner, drill 8 1/2-in. hole with HT metal-seal bits to TD and run 7-in. liner.
With a 7 5/8-in. contingency liner drill 6-in. hole to TD and run the tapered 7-in. and 5-in. string.
In both cases, the 7-in. liner hanger needs to be set 100-1 50 m inside the 10 3/4 in. string.

The 7-in. tapered to 5-in. production string offers the following advantages:

Standard 7-in. well test equipment rated at 15,000 psi can be used.
The 7%-in. contingency liner can be set and still permit the 7-in. and 5-in. production string.
Only one backup liner hanger is needed, i.e., 7 5/8 in.
Pulling the blowout preventer (BOP) stack to change rams is not required for the 5-in. liner, but would be needed for a 7-in. liner.

The 10 3/4-in. string has to be run with 14 lines strung up. If weight is still considered excessive for the derrick and overhead equipment, the string may have to be run in two sections with a casing tie-back.

All casing shoes, 20 in. and smaller, should be equipped with magnetic markers for relief-well path determination.

DRILLSTRING

Presently, HP wells are being drilled with 5-in. drill pipe to the top of the reservoir, crossing over to 3 1/2 in. pipe for penetrating the reservoir. Ultra-HP wells are drilled through the reservoir with a full string of 3 1/2 in.

A 4 1/2-in., G-120, 22.8 lb/ft string should be available on rental basis later this year. This 4 1/2-in. string meets the worst case collapse design requirements, thus forming part of the well control package for "secure and control," while offering acceptable circulating rates.

THIRD-PARTY SERVICES

Because oil-based muds are ruled out for environmental reasons, Norwegian Central Graben wells are drilled with water-based mud from surface to TD. Mud weights in the HPHT section are around 2.20 sp gr.

The high bottom hole temperature (BHT) will cause mud dehydration that risks gelation and swabbing. If testing, barite may settle out and hinder tool retrieval.

High temperatures can also cause loss in specific gravity in the range of 0.024-0.036 sp gr. HPHT static and dynamic simulation tests are required for optimum rheology determination.

Precise temperature readings are considered mandatory for cementing purposes. An error of only 4-5 C. can lead to serious cementing complications. Improved displacement by use of spacers, batch mixing, and proper slurry design will enhance the cement job, especially with respect to thickening time and control of slurry segregation and free water.

A geological, engineering monitoring, and data analysis service including measurement-while-drilling (MWD) will provide constant monitoring and recording of drilling and formation parameters.

Standard logging tools rated at 350 F. are available for all open hole services and can operate in a 6-in. hole. "Hostile environment" logging tools rated at 400 F. are available only in 23/4-in. OD and offer less resolution.

An 18 3/4-in. 15,000 psi (1,035 bar) subsea wellhead system will be installed after setting the 20-in. casing when using a floating rig. It should be noted that several of the 18 3/4-in. 15,000-psi wellheads being offered are still prototypes, and that none can be considered off-the-shelf items.

HPHT PROCEDURES

Dedicated HPHT procedures must be prepared for drilling, tripping, BOP operations, coring, testing, and well control. Some main points are to check and calibrate instruments and recorders prior to entering the HPHT reservoir. A glycol system should be ready for use. Drilling rate must be controlled so that lag time x ROP (rate of penetration) is less than 30 ft. Once drilling enters a continuous reservoir, this restriction can be lifted.

Flow checks have to be performed at all drilling breaks and at designated points when tripping out. If doubts exist at any time, bottoms up shall be circulated out over the choke manifold. Under no circumstances should a trip commence without the presence of both the operator's representative and the contractor's toolpusher.

Coring procedures should ensure that the core is brought to surface in a safe way. Depths of 1,000 m and up need to be selected for circulating in stages to free gas from the mud under controlled conditions.

Well control procedures have to cover both drilling with kelly and top drive, if top drive is used. The "fast shut-in" should be used rather than the "soft shut-in."

The standard "wait and weight" method should be modified to ensure that the limitations of the surface equipment are not exceeded, especially when gas reaches the surface.

A 25% safety factor on time or strokes should allow the top of the gas to reach the wellhead. At that time, commence glycol injection to prevent hydrate formation.

RIG AND EQUIPMENT

The drilling unit should be a large, fully equipped third or fourth generation semisubmersible or jack up rig capable of drilling deep wells.

Typical requirements are:

15,000 psi BOP system
3,000 tons variable deckload
700 tons bulk capacity
500 cu m. mud tank capacity
650 tons overhead equipment rating
14 lines string-up capability
Three mud pumps or at least two mud pumps and a riser booster pump
Accommodations for 100 persons
Full compliancy with Norwegian rules and regulations.

Few rigs, if any, incorporate specific HPHT features when delivered from the yard. Fortunately, the HPHT specifications require only minor changes (if the rig has a 15,000-psi BOP stack and is of a modern design), and they can be preformed while on location.

The HPHT particulars are mainly oriented towards pressure and temperature detection, high temperature safeguards, and drilling and well control.

Temperature and pressure sensors should be installed on the BOP stack, choke manifold, and atmospheric mud/gas separator, upstream and downstream where applicable.

A gas sensor in the suction pit will indicate the amount of gas going in the hole (not removed by surface treatment). Glycol injection shall be provided for antihydrate formation.

All elastomers on the BOP stack and its operating system have to be rated for 210 F. continuous and 400 F. peak service. Variable rams are not allowed due to the potential sealing-element failure at elevated temperatures. The only acceptable flexible hoses are Coflexip with Coflon lining for high-temperature service. Top drive is preferable for drilling, reaming, and well control purposes. The alternative is rotating elevators. The mud mixing, transfer, and solids control systems should be rated for 2.50 sp gr mud.

The mud/gas separator can become overloaded when circulating out a kick if not properly designed for anticipated throughput. The separator is usually a piece of pipe with welded-on baffle plates. For most rigs, it will have to be upgraded to HPHT standards.

For a given vessel geometry, the kill rate can be computed as a function of the throughput capacity. If this capacity is inadequate, a replacement vessel with improved geometry is mandatory.

TESTING

Most HPHT wells are scheduled to be tested in drilling mud that as result of the high mud weights have solids contents of 50% or more. Heavy brines are not recommended because of their adverse effect.

The preferred solution to reduced barite plugging is a "simple" test-string layout combined with dedicated HPHT rheology. Case histories confirm that production tests have been run successfully for 10 days and more in HPHT North Sea wells with BHPs of 15,000 psi, and around 195 C.

CONTINGENCIES

Relief-well locations need to be Chosen beforehand. The relief-well plan should include a task-force organization, simplified flow patterns, kill method, relief-well path, and definition and availability of long lead items and equipment. To prepare the crews thoroughly in HPHT procedures, the drilling schedule should start with a low-pressure well followed by the designated HPHT well. This philosophy is in line with the Norwegian Petroleum Directorate's memorandum for high-pressure drilling, to be issued early this year.