TECHNOLOGY Underbalanced coiled tubing sidetrack successful

J. Adam, M. Berry
Nederlandse Aardolie Maatschappij B.V.
Assen, The Netherlands

The technique of drilling through a completion string, underbalanced, with coiled tubing eliminated some of the problems encountered with overbalanced drilling in a group of offset wells.

This project confirmed that performing drilling operations in live wells can be carried out safely and effectively.

Relative to drilling overbalanced, this technique is an economical means of improving productivity from an existing asset and has potential for improving production potential in new wells.

Dalen is a sour gas field in the eastern part of The Netherlands and produces from vertical fractures in the Zechstein carbonate reservoir. The field currently produces about 2.3 million cu m/day from 12 wells. H2S is produced in concentrations ranging between 40 and 6,000 ppm.

All but one of the 12 producing wells have been drilled conventionally and suffer from relatively low production rates because of the inherent difficulty in intersecting directly the fracture systems. The one horizontal well in the field showed dramatic production improvements, but was costly and risky.

Nine of the 12 wells are relatively poor producers, mainly because conventionally deviated wells rely implicitly on direct intersection of fractures for production. Significant production improvements occurred in 1993 when the first horizontal section was drilled through the reservoir, intersecting several fracture systems.

Despite the production success, this horizontal well suffered severe mud losses to the formation when fractures were penetrated, resulting in excessively high costs in terms of materials and time spent combating the problem (of the order of Nfl 4 million, or about $2.5 million). Additional complications included the resulting reservoir impairment and risk of stuck equipment. Although this well was a major step forward, it was felt that improvements in drilling techniques must be pursued to overcome these problems.

Nederlandse Aardolie Maatschappij B.V. (NAM) established a project team which found underbalanced, horizontal drilling to be an attractive option for developing Dalen and other similar fields.

An added advantage of drilling underbalanced is the possibility of gauging the production contribution from fractures as they are penetrated, which is not possible with conventional drilling. Thus, it should be possible to tailor the length of the horizontal section based on observed well potential rather than just drilling to some nominal departure, which may not provide any incremental benefit.

Dalen 2 was selected as the first candidate well, having been shut in when production declined to around 30,000 cu m/day.

Well concept

The well objectives included:

• Development of an incremental 0.4 billion cu m sour gas reserves

• Confirmation of the technical feasibility and benefits of underbalanced coiled tubing drilling

• The drilling of a horizontal section in the vertically fractured carbonate reservoir for a target delivery of 1.3 million cu m/day at 230 bar tubing head pressure.

The proposal for Dalen 2 was to abandon the lower section of the original hole and subsequently sidetrack conventionally to the top of the reservoir, run and cement a 5-in. liner, complete the well with a 5-in. monobore completion, and install the christmas tree. This part of the operation would be performed with a workover hoist. Thereafter, a 334-in. hole would be drilled through the completion and into the reservoir, underbalanced with coiled tubing (Fig. 1)(16289 bytes).

The drilling proposal had to address a number of key issues:

• Creating underbalanced conditions

• Handling sour gas production at surface

• Handling and treating drilling fluids at surface

• Removing drilled solids from the returned fluid system

• Deploying a long coiled tubing drilling bottom hole assembly (BHA) into a live well.

Creating underbalanced conditions was relatively straightforward. With an expected reservoir pressure of 335 bar at 2,890 m true vertical depth (TVD), a 1.06-sg NaCl brine would facilitate creating underbalance (including the allowance for additional back pressures resulting from equivalent circulating densities).

If the low-density drilling fluid alone could not effect the desired bottom hole conditions, underbalance could be promoted by annular injection of N2 through a side-pocket mandrel at 985 m measured depth (MD) in the completion string.

NAMs operating policy requires minimal emissions during well testing; thus, flaring produced gas had to minimized. To handle the produced gas, returned drilling fluids, and drilled solids, a standard well test equipment setup was modified and reconfigured for the underbalanced drilling operation (Fig. 2)(36533 bytes).

Gases and liquids would be separated conventionally with a three-phase separator. The gas would then be directed to the existing gas-handling facilities at the Dalen 2 location or to flare if necessary. Production via the existing facilities would fulfil the operating philosophy of minimized emissions, while also boosting the systems capacity for gas sales. The proposed well test equipment configuration would allow gas to be exported or flared during drilling and tripping.

Downstream of the separators, the liquid phases (condensate and drilling fluid) would be directed to their respective surge tanks. Thereafter, the condensate would be trucked off location, while the drilling fluids would be treated and then returned to the active drilling fluid system. As there was the potential for H2S gas, which is soluble in the drilling fluid, a closed-tank drilling fluid treatment and storage system was required, again minimizing the chance of gas emissions.

Drilled solids would be removed by a set of sand filters and sand catchers upstream of the choke manifold and separator. This setup was considered sufficient because the anticipated volume of drilled solids was very low (4 cu m). In the event of operational problems associated with the well test equipment, an automated high and low-pressure alarm and shutdown system would be available as standard. It should be noted that the shut down system would only shut in the well test equipment, and all the coiled tubing equipment would have to be operated independently through the blowout preventers (BOPs) and mud pumps.

Deploying the coiled tubing bottom hole assembly (CT BHA) into a live well presented a new challenge because the CT BHA was about 23 m long.

The conventional method for deploying long assemblies into a live well (typically perforating guns or logging tools) involves the use of wire line units, deployment bars, and wire line lubricators. These wire line deployment techniques are cumbersome and time consuming. Therefore, an alternative approach involving the use of a subsurface safety valve (SSSV) was proposed.

The SSSV would be installed in the completion string at 107 m MD and used to isolate reservoir pressures from surface, effectively creating a downhole lubricator system. This setup would allow the CT BHA to be run into and out of the live, but isolated, well.

During rigging up and rigging down of the coiled tubing injector head, the CT BHA would be suspended in a deployment BOP, providing a secondary safety barrier against reservoir pressures. Pressure isolation via the CT BHA would be provided by a dual check valve arrangement.

If this BHA deployment technique could not be used for any reason (for example, a leaking SSSV), then a conventional lubricator system would be on standby at the location.

Although it was perceived to be feasible to engineer such a project and to manage all aspects relating to health, safety, and the environment, there were still some major hurdles to overcome, including the restriction that drilling without the primary well control provided by the drilling fluid is not permitted under Dutch legislation.

Planning

Some 8 months before the execution phase and in keeping with NAMs Integrated Approach to Well Engineering (IAWE), a multidisciplinary team was established to develop the detailed engineering and supporting documentation for the project.

NAMs IAWE is a structured approach to well engineering, such that key deliverables for a project are defined in terms of input and output as are the responsible parties, tasks, and critical timings. The approach encompasses a team (partner) approach to projects, capitalizing on the pooled expertise of the team members and of others. Within NAM there are two core partnerships, namely GO for offshore and Prostar for onshore projects. For Dalen 2, Dowell Schlumberger and Baker Hughes Inteq are representatives of the NAM onshore partnership. (The other members, Deutag and British Plasterboard, had no workscope in the project.)

The team included full-time representation from drilling engineering, production engineering, and petroleum engineering, as well as a Dowell coiled tubing specialist, and directional drilling, BHAs, and bits from Baker Hughes Inteq.

When necessary, the team was further supplemented by other expertise for completion design; production technology; hazard identification; hazard and operability studies; annular pressure modeling; CT modeling; health, safety, and environmental issues; training; concurrent operations; witness testing of equipment; procedures and guidelines; well trajectories; drilling fluids for H2S environment; special equipment; review and feedback on program; and contracts and procurement services.

Legislative issues

The initial task of the team was to develop a project proposal for presentation to the State Supervision of Mines (SodM) to gain its views and support for underbalanced drilling activities. The concept of operating through a completion string with CT while producing gas is a common feature in NAM well service operations.

It was thus imperative that the team could demonstrate that drilling and associated operations, under similar conditions, could be performed without hazard.

A presentation was made to SodM in October 1994, and following a very constructive discussion, SodM stated that it was not opposed to the proposal. SodM did, however, wish to see a fully developed Health and Safety Report (Safety Case) prior to any further commitment.

The Health and Safety Report for Dalen 2 was developed as an umbrella document containing details of hazard identification (Hazid) and hazard and operability (Hazop) studies, a concurrent operations script, a detailed CT drilling program, and an emergency response, firefighting, and rescue plan.

The Hazop study addressed four main areas:

1. The procedure for deploying the BHA using the tubing-retrievable SSSV

2. The interface between the coiled tubing and the well test unit

3. The produced fluid conditioning and recycling system

4. The well test unit and production installation interface.

Because the Dalen 2 project was to be carried out concurrently with three other wells being produced on the location, a concurrent operations script had also to be prepared to assist in the management of the site.

On completion of the Health and Safety Report, a full technical presentation of the project was made to Dutch authorities on Feb. 2, 1995, 4 months after the teams initial approach. Following a review of the documentation detailing the project and some minor clarification, SodM responded (within 5 weeks) with no objection to the proposal.

This cleared the way for the first underbalanced drilling program ever to be carried out in The Netherlands (and the first in the Shell Group to attempt drilling with CT while producing).

Well preparation

Concurrent with the approval process, Dalen 2 was worked over, with the proviso that should approval not be granted by the authorities, the reservoir would be drilled overbalanced.

The first phase was to abandon the original hole section and prepare the well for subsequent sidetracking. This step involved removal of the old production tubing and plugging back of the perforated interval. The next step was to cut and retrieve the 7-in. production casing and replace it with a new 758-in. 3 7-in. tapered string. The 758-in. casing was run from surface to 1,004 m MD to accommodate the larger outside diameter of the 5-in., tubing-retrievable SSSV (and control lines) and the side pocket mandrel forming part of the 5-in. monobore completion.

The second phase was to sidetrack from below the new 7-in. casing shoe and drill a 578-in. hole to the anhydrite above the reservoir. During drilling, however, the reservoir was penetrated by some 20 m, whereupon dynamic mud losses of about 30 cu m/hr occurred, indicating communication with a fracture.

The open hole was subsequently plugged back, and the cement dressed off to the overlaying anhydrite before the 5-in. liner (shoe some 3 m TVD above the 50-m-thick reservoir) was run and cemented. The hole angle at shoe depth was approximately 60. The 5-in. liner shoe track was drilled out prior to the running and stabbing of the completion string into the top of the 5-in. liner tie-back polished bore receptacle (Fig. 3)(17731 bytes).

The operation was subsequently suspended following installation and testing of the christmas tree, awaiting reentry with coiled tubing.

CT rig up

Dowell provided a new 2-in. coil with wire line installed specifically for Dalen 2. As part of the qualification testing of the equipment, a yo yo test was conducted to check the fatigue life as predicted by the Dowell CoilLIFE model. The test was successful and correlated very well with predictions.

During the test, however, elastomer backing pads in the injector head were extruded from the injector chain. This problem was attributed to excessive skate pressures being applied continuously, and the problem was overcome.

In addition to providing all the equipment and services relating to coiled tubing operations, Dowell also coordinated and supervised the surface test equipment hookup and services provided by Schlumberger.

Baker Hughes Inteq was initially responsible for providing the BHAs and all directional drilling planning. About 2 months prior to the execution phase, the company withdrew from the project because of technical problems on another job.

As a consequence, Ensco was contracted to supply the necessary directional drilling equipment and services at a relatively late stage, being the only other company available to supply downhole pressure gauges with real-time surface read out in the 3-in. BHA, deemed to be essential for this first underbalanced well.

Mobilization and rigging up of the surface well test and CT equipment began on Mar. 6, 1995. Rig up was carried out strictly under a permit to work system and only during daylight hours.

Because of the large amount of equipment to be placed, two cranes were employed on site during this phase of the operation. Prior to commencing rig up and each subsequent morning, a general safety meeting was conducted by NAMs head of concurrent operations.

Rigging up was completed in 49 hr, with another 3 hr spent functioning and pressure-testing equipment.

Following equipment rig up, all the site personnel attended a full day training session at NAMs de Boo training center in Schoonebeek, The Netherlands. The training sessions included details of the project objectives, petroleum engineering aspects, an overview of the drilling and associated programs, details of the documentation available and their location for reference, specific operating procedures such as operation of the downhole safety valve and BHA deployment, concurrent operations overview and data gathering, reporting requirements, and an H2S training refresher.

Drilling program

The program for the well was to reenter with a coiled tubing drilling assembly, drill out the cemented pocket below the shoe, and build angle to approximately 85 by mid-reservoir (50 m thick, 38 m TVD below the 5-in. shoe at a depth of about 2,923 m TVD). A 1.06-sg NaCl brine would be used as the drilling fluid, which would underbalance the formation pressure, taking into account circulating pressures. When necessary, N2 could be injected through a gas injection valve at 985 m MD to assist in providing additional underbalance.

Drilling would proceed, with an angle of 85 maintained through the reservoir until the gas production target of 1.3 million cu m/day was achieved.

A late addendum to the program was to perform an acid job once the cemented pocket had been drilled out to try to reestablish communication with, and possibly realize gas production from, the previously encountered fracture.

Operations began on Mar. 13, 1995, with wire line work to prepare the well for underbalanced operations. This entailed a dummy run to establish holdup depth and replacement of the dummy assemblies in the side pocket mandrel and tubing-retrievable SSSV nipple, with an open circulation valve and safety valve, respectively.

Protection sleeves were also set in the wire line-retrievable SSSV nipple and in the tubing-hanger nipple. Following the wire line work, the CT BOP stack was nippled up and pressure tested. The injector head assembly was lifted into place on the jacking frame and mounted on the CT rig floor.

BHA deployment

The first directional drilling BHA was made up in two pieces together with a 334-in. barracuda mill for milling out the cement pocket below the liner and drilling to the reservoir top (Figs. 4 (16776 bytes)and 5)(28451 bytes).

The BHA was suspended in the 3-in. inverted deployment rams and pressure tested between the rams and the stripper to check the quick-lock connection between the BOP stack and the injector riser. During the test, the pressure bled off at 110 bar, and the electrical connection to the BHA was lost.

It was subsequently found that the shear disconnect sub had sheared. Despite a 2,000-lb compressional load being applied via the injector, the disconnect was thought to have been triggered by movement of the string from the test pressure acting on varying surface areas in the tool configuration. The injector head was disconnected and skidded to the side, and the fish was retrieved from the rams by an overshot suspended from the crane.

The BHA was reconfigured with a short Monel drill collar run directly above the orienting tool such that the 3-in. inverted rams could be closed above the orienting tool, thus isolating it from the test pressure. It was felt that test pressure had initiated movement within the orienting tool, resulting in the shear off. After some remedial actions to eliminate leaks, the assembly was fully tested and run in the hole.

Drilling out cement

The top of cement in the shoe was located at 2,978 m MD. Drilling was initially slow, exacerbated by the high circulating pressures in the system. Following the addition of friction reducer (XanvisL), the circulating pressure was reduced from 300 to 200 bar at 300 l./min.

The drilling rate varied extremely, but 3 m/hr was achieved in drilling the cement pocket to 2,985 m and formation to 3,001 m without gas lift.

At 3,001 m, a N2 gas lift test was conducted to gauge the circulating parameters compared to the modeled values, prior to any reservoir penetration.

Drilling continued to 3,002 m with no further progress. The assembly was pulled, and the mill was 50% worn and O-ringed.

Acidization

Because of the fracture being encountered while the sidetrack for the 5-in. liner was drilled, the business unit requested an attempt to acidize the formation and induce connectivity with the fracture. The acid job was performed by spotting some 3.5 cu m, 15% HCl using NaCl brine as the displacing fluid. The pill was circulated out with no significant indications of gas.

BHA deployment changes

Drilling progressed to 3,009 m, where it was no longer possible to orient the BHA, and the electrical connection was lost. The assembly was retrieved, and a short circuit was detected and rectified. The BHA was rebuilt.

Prior to running the BHA in the hole, the tubing-retrievable SSSV, which was being used as a lubricator valve, was opened by applying control line pressure and pressure assistance via the annulus to the tubing. On the valve opening, 50 bar rapidly bled off from the completion tubing, and the electrical signal from the BHA was lost.

On pulling out, it was discovered that the disconnect sub had sheared, and the lower part of the assembly had been lost in the hole. This incident was investigated, and it was concluded that by applying pressure via the CT/tubing annulus, the orienting tool (which is spring loaded) was compressed by the action of the pressure on the float valves in the string.

With the sudden release of pressure on opening the tubing-retrievable SSSV, the orienting tool operated like a down jar with sufficient force to shear the disconnect sub (Fig. 6)(25395 bytes). On subsequent trips, the pressure applied to assist opening the tubing-retrievable SSSV was applied through the CT, eliminating the problem.

Fishing

The BHA was successfully fished; however, a small finger of steel was left in the hole from the disconnect assembly (1 3 1 3 0.5 cm). A subsequent run with a reverse circulation junk basket resulted in the assembly standing up some 12 m off bottom.

On pulling out, some metal debris from the shoe track was recovered. It was also noted that the control line pressure of 5 bar had bled to zero, indicating that the wire line-retrievable SSSV sleeve had been dislodged.

The tubing hanger sleeve and the wire line-retrievable SSSV sleeve were pulled as a precautionary measure. Both were found damaged, and they were replaced.

A milling assembly made 1.5 m of progress with indications of junk (stalling mud motor). On pulling off bottom, overpull was seen, and the electrical signal was lostthe BHA had been lost. The assembly was fished without difficulty, and no indication of junk on the mill was observed.

Stuck

Drilling progressed at 2 m/hr to 3,018 m, where the string became stuck as it was pulled back to take a survey. Full circulation was possible, and it was still possible to rotate the orientation tool.

Over time, the ability to orient the tool was lost also. In an attempt to free the string, the entire well was displaced with N2, but to no avail. At this stage, even with the well displaced with N2 and the wellhead pressure bled to zero, no influx of gas from the carbonate was observed.

The well was displaced back to brine. Attempts to shock the string by reducing internal CT pressure rapidly were also to no avail. On a subsequent attempt, the shear sub was inadvertently disconnected and all electrical signals lost. The remainder of the assembly was retrieved, and the decision was taken to plug back.

A gamma ray/casing collar locator log was run to check the depth of the fish and provide a base log for later correlation with the measurement-while-drilling gamma ray. The top of fish was located at 2,996 m, some 11 m below the liner shoe, leaving sufficient space for sidetracking. The section was plugged back with 0.5 cu m of 1.92-sg Class G cement slurry using a 112-in. CT unit for placement.

Up to this point, the well had been drilled underbalanced simply by using a low mud gradient (apart from the N2 lift trial).

One theory for the pipe becoming stuck was that debris was induced to fall in the well because of the underbalanced conditions. As a consequence, it was recommended to proceed with the sidetrack with a higher drilling fluid gradient to balance the formation pressure.

Sidetrack

The cement was tagged at 2,963 m, and drilling proceeded to 2,996 m (coincidentally the top of the fish) when the motor stalled. The motor was found jammed with pieces of rubber from the stator. The bit showed no signs of junk damage.

Production

As the next assembly was run in at 2,994 m, the well started to unload brine and commenced producing gas at 15,000-30,000 cu m/day with a flowing tubing head pressure of 44 bar.

The choke was manipulated to maintain a bottom hole pressure of 285 bar (5 bar), and drilling continued to 3,021 m. At this point, the well inclination had dropped, instead of the planned build, from 57 to 40 (in 30 m). This drop resulted from a computational error on the part of the directional driller while inputting the tool face to steering tool offset.

Orientation difficulties

From this point on, various attempts to build angle and steer the well on course were futile for various reasons, the main factors being the following:

• Because the well was producing, the differential pressure between the inside and outside of the drilling assembly tended to act on the internal holding slips of the orientation tool, making it very time consuming and often impossible to orient the motor. Some success was achieved by equalizing the pressure in the CT string with N2, allowing the holding slips to release for orientation.

• The effect of the extreme hole geometry on the bent BHAs could not be overcome by the orientation tool, and the hole tended to spiral uncontrollably (Fig. 7)(25150 bytes).

Second fracture system

The well was deepened to 3,062 m, where a drilling break was observed (penetration rate increased to 18 m/hr from 3 m/hr).

Drilling continued to 3,064 m, when the bottom hole and wellhead pressures suddenly jumped. Some 30 sec later the well was producing at 300,000 cu m/day.

Drilling continued to 3,087 m with gas production rates varying between 250,000 and 600,000 cu m/day. Initially, the well was produced to flare until the flow stabilized, and then the gas stream was diverted to the production facilities.

Project termination

Directional control up to this point had proved still to be extremely problematic, although the hole angle had recovered to 70. A further complicating factor concerning the orientation tool emerged when the elastomer O-ring seals in the equipment were found extruded because of temperature degradation.

At this stage, no further progress could be made. The combination of temperature effects and the underbalanced drilling conditions downhole left insufficient confidence that the well could be completed as planned using the drilling BHA without modification to address these issues.

Thus, the operation, in agreement with the client business unit, was curtailed.

Lessons learned

• When pressure testing riser connections with a BHA or tools inside the riser, it is imperative to understand the interaction and consequential effect on the tool string. Experience from Dalen 2 revealed that test pressures initiated movement within some equipment (orienting tool) with disastrous results (that is, shearing of disconnect subs).

• Ensure that any BHA to be run in the hole is long enough to place the bottom of the BHA below any surface obstructions or ledges (internal diameter changes, BOP cavities, christmas tree gate valves, tubing hanger nipple, etc.) before attaching the coiled tubing. In Dalen 2, the residual bending stress in the 2-in. coil, once it had been passed through the injector head, was difficult to overcome until there was a sufficient length of coil run in the hole. The resulting problem was that the forces in the coil directed the BHA against the side of the well/wellhead, causing the tools to stand up.

• Viscous pills aimed at sweeping debris from the bottom of the hole are not really effective with this hole size and BHA size combination. As the coil and BHA IDs are restricted, circulation pressure and hence circulation rate are also restricted until the viscous pill is substantially displaced out of the BHA. The larger the pill volume, the more profound the problem.

• If a gamma ray tool is required in the BHA, consider placing a radioactive marker as deep as possible in the last casing string. This marker will allow for simple in-hole depth calibration of the coil tubing.

• It is essential to take early delivery of new or uncommissioned equipment for qualification testing purposes. For Dalen 2, early delivery of the 2-in. coil allowed fatigue testing to take place. The actual fatigue test results compared favorably with computer model fatigue life predictions.

During this testing schedule, problems with extruding elastomers on the 2-in. injector head chains were experienced and resolved. Hindsight also indicates that investigation into the mechanical operation of the BHA should have been undertaken with respect to the underbalanced well conditions and the way in which these conditions could influence tool operation.

In Dalen 2, high differential pressures across the BHA promoted by the underbalance resulted in slips in the BHA remaining locked when it was desirable to have them unlocked. Certain equipment was also unsuitable for the high bottom hole temperatures (motor stator and seals located in the BHA) and the corrosive nature (H2S, CO2, natural gas, and high pH drilling fluid) of the well bore fluids.

• A substructure was specially commissioned to accommodate the wellhead and CT BOPs and to support the injector head frame. The injector head could be lowered onto and raised from the wellhead hydraulically, which very much proved to be a labor saving and time saving investment.

Skidding the injector head to the side of the wellhead remained a manual operation and proved to be cumbersome and time consuming. The injector head frame would therefore benefit from the introduction of an automated skidding mechanism.

• The handling of BHAs in general also proved to be very time consuming. The makeup and breakout of BHAs would benefit from the addition of a dedicated rig-floor power tong and dummy rotary table.

• Personnel requirements for the underbalanced drilling operation demanded primarily expertise from two disciplines, namely coiled tubing operators and well test operators. Experience on Dalen 2 revealed that at no time during the operation were both crews fully used, and multiple-skilled crews, to reduce crew levels, should be a serious consideration on subsequent jobs.

• The late program addendum to perform an acidization directly below the 5-in. shoe should, with the benefit of hindsight, have been avoided. Following the acid job, junk that had presumably been embedded in the hole wall or cement was freed and halted further drilling progress.

Shortly after fishing the junk and while attempting to continue drilling, the BHA became mechanically stuck and was lost in the hole. It is assumed that a fragment of loose cement or formation from around the 5-in. shoe had dropped on top of the BHA.

Results

Undoubtedly, the Dalen 2 project demonstrates that the technique for drilling underbalanced is sound, particularly in the areas of safety and ability to handle assemblies in live wells. Furthermore, controlling the level of underbalance of the reservoir was relatively straightforward.

The inability to steer the well on this occasion was of course disappointing but is by no means insurmountable. High rates of penetration up to 18 m/hr (typically 2-3 m/hr conventionally) were observed. Certainly, there were strong indications that sustained performance improvement is feasible. In this case, controlled drilling for most of the hole section prevented full demonstration of this feature.

Overall, the client business unit is encouraged by the results to date, although the 360,000 cu m/day at 75 bar tubing head pressure, with the well on test, falls short of the target.

To put the project in context, however, in terms of production the Dalen 2 ranks second only to the horizontally drilled well Dalen 15 (1.2 million cu m/day with a 414-m horizontal section through the reservoir).

The up-front engineering effort and training of personnel were key factors to the success of the project, and furthermore it is to the credit of all involved that no safety-related incidents occurred.

An interesting feature of the project is that in the first hole section, prior to sticking the string, despite the well being completely N2-filled and the wellhead pressure reduced to zero, no gas was observed. In the sidetrack at the same depth and in very close proximity to the original well, the well kicked into production at 15,000-30,000 cu m/day in a fluid-filled hole.

Possibly, this difference gives some insight into the plugging effects of cement (in the workover phase, a loss zone was plugged back prior to running the 5-in. liner) and the ineffectiveness of acid in some cases in removing the damage. One then has to seriously consider the effect of cementing casing across such formations and the dire consequences on production.

Future

The business unit has committed to reenter and extend the trajectory in Dalen 2 once an alternative BHA configuration is prequalified. At least two other (new) wells will use the technique.

It is foreseen that through-completion drilling will develop and offer an attractive means of improving production from existing assets and developing traditionally low productivity reservoirs, with scope for significantly increasing the gas reserves which would remain otherwise unproduced.

Acknowledgment

The authors would like to thank the industry partners as well as the project participants from the engineering, petroleum engineering, production operations, and well services department of NAMs land gas business unit for their assistance. The authors also thank Shells research laboratories in Rijswijk for their contributions. n

The Authors