Wells drilled using slim hole techniques are reducing initial drilling costs. The technology to conduct effective petrophysical evaluation in slim wells is available. Thus, slim hole development wells should be considered for many projects. Wells in fields will not flow at the rates traditionally required to justify subsea producers and smaller production conduit may be adequate.

1 Monobore completion

"A monobore completion is a completion featuring fullbore access across the pay zone, without diameter restrictions (but not necessarily with a constant diameter from top to bottom)".

The primary difference is that the monobore completion inner diameter tapers downward with the smallest inner diameter being the production liner (or casing) whereas the conventional completion tapers down to a minimum inner diameter, usually located at the base of the packer tailpipe, and the production liner (or casing) is of increased inner diameter.

The emergence of slim hole drilling technology now allows hole sizes such as 4 1/8" and 4 3/4" to be drilled quickly and reliably: These hole sizes are appropriate for 3 1/2" OD liners. Additionally, a large proportion of wells are adequately serviced by 3 1/2" production tubing. Use of a 3 1/2" production liner, in conjunction with a 3 1/2" production tubing allows the cost savings associated with slim wells to be achieved while maintaining an outflow system suited to a large proportion of wells.

1.2 Advantages

The key advantage of the monobore completion is that the opportunity for low cost (rigless) well intervention is maximised. Another major advantage is that well impairment and formation damage is mitigated because the monobore is suitable for intervention techniques such as slick line, braided line and coiled tubing; these can safely be conducted on live wells.

Other advantages include:

• The completion is simple, requiring a minimum of equipment to be installed in the well at the time of completion.
• The largest possible perforating guns can be run into the production liner so that casing guns can be used where desirable.
• Reliable, low expansion, selective placement tools can be used within the production liner.
• Scale clean out operations of the liner are easily achieved on coiled tubing or with a snubbing unit.
• Full bore production logging tools can be used.

1.3 Disadvantages

• In many cases, a monobore completion requires more casing/liner flow than in a conventional completion. This may have two implications:
• Limited ability to circulate a well dead at the top of the productive zone. This is generally not a concern because most wells can be bullheaded dead, and the option of placing a retrievable bridge plug in the top of the liner section and circulating the well dead above it is possible.
• Corrosion of the liner may cause irreparable problems. This can generally be pre-empted by appropriate materials selection for the liner. Also the costs of sidetracking round mechanical damage, corrosion and formation impairment have fallen relative to workover. In many cases a sidetrack round a corroded liner may be justifiable.
• If monobore plugs become stuck in the liner, it becomes necessary to mill them out compared to a conventional completion where it may be possible to hoist tubing and retrieve a stuck plug or even to 'shoot off' or 'perforate' a packer tailpipe to restore production in the event of a stuck plug.
• Generally, when a monobore completion is run in larger sizes, the tubing size selected is one size larger than liner size. For instance, 5" tubing is set above a 4 1/2" production liner: this completion will tolerate scale build up in the tubing while still facilitating full bore access to the production liner. In the 3 1/2" monobore completion, all scale build up would have to be removed from the entire production tubing to allow full bore access to the production liner.
• The limited operating history of 3 1/2" monobore tools is an issue. An extensive favourable operating history for 4 1/2", 5" and 5 1/2" monobore operating tools is available. Indications are that the 3 1/2" tools will perform favourably but operating experience is required.
• Slip damage to the production liner arising from use of monobore tools can act as a point of initiation for corrosion. The consequence of slip damage initiated corrosion in and adjacent to the productive interval is probably not an issue but is a concern in the liner section above the producing interval.
• In the case of a 3 1/2" liner, flow velocities while producing and subsequent to perforating underbalanced may inadvertently lift tools. In most cases, it is expected that this can be managed with appropriate job planning but tool lifting by flow must be recognised as a potential hazard.
• In the event of a poor primary cement job, remedial cementing in a 3 1/2" production liner is expected to be difficult.

2 Alternative well designs

Depending on the objective and particular completion considerations, an endless variety of alternative well designs is possible. Some of the obvious alternatives, complete with respective advantages and disadvantages, are detailed below.

2.1 Conventional completions

The merits of conventional tubing/packer/tailpipe completions should not be overlooked. In many areas, it is not necessary to set casing prior to penetrating the reservoir. Where possible, a conventional well design with 4 1/2", 5" or 5 1/2" full string production casing will likely result in lower initial well costs. In this case, it is necessary to decide whether the advantages of a monobore completion will more than offset the cost of setting a 3 1/2" liner.

The monobore completion is not particularly suited to wells where zonal selectivity is required. Where selective completions are required, a conventional completion is likely the preferred choice. Prior to committing to a well with selectivity, one should challenge whether:

• Commingling of production with (or without) production logging to allocate production to reservoirs is an option. The value of conventions/regulations prohibiting commingled production should be challenged. In the event that commingling is acceptable, a monobore completion may become the most effective option.
• A sequential, bottom up, depletion strategy is appropriate. In this case, a monobore completion is ideal and the many operational advantages of the monobore completion could be realised.

In many low rate wells, production tubing diameters smaller than 3 1/2" tubing (typically 2 3/8" and 2 7/8") are required to achieve vertical flow stability and allow natural flow or optimised artificial lift. The lack of availability of  monobore tools and equipment suited for use in 2 3/8" tubing or 2 7/8" tubing, will make the conventional completion an obvious alternative. Where 2 7/8" or smaller tubing is required, coiled tubing can be used to achieve conventional (non-monobore) completions.

When pumping is the preferred artificial lift option, a conventional completion is likely to be more desirable than a monobore completion. Regardless, the pump effectively precludes a monobore completion.

2.2 Tubingless completions

Tubingless completions are completions with production flowing up the casing without a production tubing. This completion style is suited to applications where no production casing annulus is required for artificial lift and the consequence of a casing leak is minor. Although tubingless completions have predominantly been used in America in low rate wells, they are also used in the Middle East and North Africa for very large diameter high rate completions. They may be the most cost effective alternative in appropriate niche applications.

2.3 Coiled tubing completions

The availability of large diameter (two inches and larger) coiled tubing (CT) has made CT a viable alternative to jointed tubulars for initial completions and recompletions. It has become routine to install coiled tubing to serve as a velocity string in gas wells to improve flowing tubing hydraulics. Available technology make it possible to install coiled tubing complete with packers, subsurface safety valves, and gas lift mandrels to serve as a recompletion or initial well completion.

Ttwo types of coiled tubing completions ar eavailable: conventional and spoolable. In the conventional style, standard side pocket mandrels are inserted into the coiled tubing string as it is run into the well: This completion style has the advantage that conventional wireline work such as bottom hole pressure surveys can be run. In the spoolable style, concentric gas lift mandrels and surface controlled subsurface safety valves are installed within the coiled tubing resulting in a slick OD which can be installed/retrieved directly from/to a coiled tubing reel. This style of completion is safer to install and can be installed within tighter tolerances.

3 Inflow performance

Although the effect of reduced wellbore diameter must be examined on a case by case basis, the effect is often minimal.

Upon examination of the PI relationship, we can immediately conclude that:

Skin has significant direct impact on well productivity. The skin effect, which is resultant from a pressure drop across the completion, is a summation of a number of factors:

Skin due to partial completion often overwhelms the other skin effects. When a monobore completion is used, one can choose a comparatively aggressive initial completion interval and shut off perforations as required therefore mitigating the detrimental effect of partial completion.

Effective perforations generally contribute negatively to total skin. The effect of perforation diameter, depth, phasing and shot density will be specifically discussed in the section on perforating.

Skin due to damage can also contribute significantly to total skin.

One of the potential benefits of slim hole drilling, due to reduced mud circulating volumes, is that proportionately more money can be spent on the mud system on a unit of volume basis and proportionately more of the mud can be processed with solids control equipment keeping the mud in better shape. Given that better mud is used, the amount of skin damage attributed to drilling should be proportionately less. Although unproved, this postulation warrants consideration.

If one assumes that the volume of filtrate invasion is directly proportional to the filter cake permeability and area, one can argue that the depth of filtrate invasion (not radius of invasion) will be less as wellbore diameter is reduced. Calculations have shown that when borehole diameter is reduced from 8 1/2" to 4 3/4", the thickness of the invaded zone is reduced by 20%.

If it is determined that the skin due to damage is positive, the formation damage can often be partially removed by an acid treatment. As a result of a successful acid job the skin factor may be reduced to zero or even become negative.

Increasing the effective permeability (k) in the near wellbore region will directly improve a well's productivity index. This has traditionally been achieved by use of hydraulic fracturing techniques.

In certain cases, such as a steam flood of viscous heavy oil, the resulting reduction in viscosity can yield significant increases in productivity.

Since re/rw appears as a logarithmic term, it has little influence on the PI and alteration of the ratio by, for instance, underreaming the wellbore to increase rw, is seldom considered as a means of well stimulation.

Based on this simple argument, we can conclude that wellbore diameter has a minor direct effect on productivity index.

Wellbore diameter has little direct impact on the inflow of a well. For instance, the PI impact of reducing wellbore diameter from 8 3/4" to 4 3/4" is comparable with reducing wellbore diameter from 12 1/4" to 8 3/4". Traditionally, a 12 1/4" wellbore has been justified on the basis of inflow performance only by exception.

If for instance, the skin due to damage of an 8 3/4" wellbore is 4, and the estimated depth of damage is 0.105 m; then one would predict that the relative productivity of a 4 3/4" wellbore is 0.9 times that of the base 8 3/4" wellbore. Clearly, the productivity impact of reducing wellbore diameter for open hole completions must be carefully considered on a case by case basis.

When assessing the effect of reduced wellbore radius on inflow performance, one must remember that:

1.Critical rate limitations may limit well production rates making loss in PI due to reduced wellbore radius insignificant.

2.Some slim hole drilling techniques, such as the Shell/Eastman system, making the incremental cost of drilling a horizontal well through the payzone small.

3.Use of a monobore well completion style allows more aggressive initial perforated intervals to be selected resulting in less geometric skin.

Also, on perforating, in a cased through and perforated completion, the effectiveness of the perforations has an overwhelming effect on well inflow performance and wellbore radius is thereby insignificant.

4 Perforating

The fundamental objective of well completion design is to maximise the economic contribution of wells over their life time with due consideration for all factors such as reliability, safety, operating and reservoir and mechanical considerations. In the context of perforating a cased well completion, this objective will generally be met if the perforations maximise productivity from the perforated interval.

4.1 Effect of partial perforation and wellbore deviation

The skin effect caused by partial perforation and deviation, Sc+q, has been described by Cinco-Ley et al. In cases where an interval is partially perforated to avoid water, gas or other production problems, or when the wellbore penetrates the pay zone at high angles, these skins often dominate.

In general, the geometric skin (Sc+q), associated with partial completion and drift angle is not significantly different between 4.75" and 8.75" wellbore diameters. No specific consideration of geometrical effects is warranted when planning perforation programmes in slim hole wells.

4.2 Effect of perforations

Perforations through the damaged zone can significantly reduce skin. The primary controllable factors which effect the Spare depth of penetration into the formation, shot density, shot phasing and perforation diameter.

For a 3 1/2" perforated liner, significant gains in well productivity can be achieved as phasing is increased from 0° to 90°. A small improvement can be expected if phasing is changed from 90° to 60°.

Benefits that can be achieved by high shot densities, particularly in highly anisotropic formations.

Perforation diameter has a relatively minor role in determining productivity in non-gravel packed wells. For most oil wells, perforation diameters of 0.3" are generally adequate. (Perforation diameter is an important parameter in certain specific types of completions, e.g. internal gravel packs and high rate gas wells).

4.3 Operational considerations for slim hole perforating

Efficient use of the small volume within a 3 1/2" production liner is the major consideration in slim hole perforating. One is forced to compromise between perforation charge size, perforation gun type and performance, drawdown and the risk of sanding the guns in.

One problem that occurred when wireline perforating a 3 1/2" production liner underbalanced, was that the perforating guns were blown up the hole and then got stuck. It is important to ensure that enough sinker bar is run to overcome the effects of drawdown.

Another problem when perforating underbalanced is the influx of formation into the annulus between the production liner and the perforating guns causing the guns to become 'sanded in'. Local experience, with regard to formation sand influx, must be considered in designing a slim hole perforating job. If large (massive) sand production is associated with underbalanced perforating, one should consider perforating at or near balance followed by perforation washing or acidisation (if required).

Strip guns are generally not used due to:

• the lack of debris containment associated with hollow steel carriers,
• the lack of containment of rogue charge energy and the consequent detrimental effect on the casing, and
• possible fishing difficulties with strip guns.

Modern strip guns utilise high strength charge housings which should prevent damage to casing.

Schlumberger's Enerjet guns utilise a solid carrier bar in an effort to mitigate the probability of parting guns resulting in retrieval problems. The JRC strip guns are of a two wire construction which can lead to problems in conventional tubing/packer completions, especially if only one wire breaks (which if failure occurs, is usually the case). This results in a fish hook which is particularly difficult to pull up into a packer tailpipe: Re-entry into a packer tailpipe is not an issue in a monobore completion so the risk of difficulty in retrieving strip guns is smaller in these circumstances.

The problem of debris generated by strip guns still remains. For instance, JRC's Dyna-Cap gun with 21 gm charges generates debris weighing 180 gm and having a volume of 6.9 cc per charge.

Although testing has not been conducted on the various perforating guns, the JRC 2.13" Multiphase Dyna-Cap appears to be a good compromise and is currently available. It incorporates large (21 gm) charges, 4 SPF, approximate 90° phasing.

4.5 Perforating conclusions

• A slim hole perforating gun should have a high depth of penetration.
• Although shot densities of 4 SPF are adequate in many isotropic formations, higher shot densities will yield benefit in anisotropic formations.
• Shot phasings of 90° (or less) are desirable.
• Initial gun developments should emphasise perforation depth once shot diameters of 0.3" have been achieved.
• Guns for perforating 3 1/2" liners in monobore wells are currently available.

Further gun developments is carried out by the service industry in response to industry demand.

5 Sand control

The sand control options for slim hole wells are listed below with a discussion of their respective merits and drawbacks. In principle, most forms of sand control can be applied in slim hole wells. The effect of smaller diameter on overall productivity, compared to conventionally sized completions, has been shown to be low. Thus, for slim hole wells, the issue of low impairment during the completion phase is just as critical as for conventionally sized wells.

5.1 Mechanical options

The simplest and probably cheapest type of sand exclusion completion, would be to install a prepacked liner into an open hole section. Where there is only one completion interval, and the risk of formation failure is considered small, this option should be considered as the initial productivity could be quite high. However, depending on the prepack selected and the formation particle size distribution, there is the danger that the prepacked screen will plug as the formation packs around it, potentially reducing productivity. Also, there is no scope for zonal isolation in this type of completion.

Normally, when a well has sand exclusion applied, there is a reduction in productivity. This technique is rapidly losing favour due to its poor productivity. Several new gravel packing techniques are currently being tested but none has led to substantial improvement in productivity yet. Slim hole IGPs are successfully installed, using 1" wire wrapped screens (WWS). They are also installed through tubing.

In conventionally sized completions, an external gravel pack would be more productive than the IGP, due in part to the absence of perforations. In the slim hole case, the under-reamed hole diameter from a 4 1/8" pilot hole would be ± 8". If casing has to be milled, prior to under-reaming, the external pack tends to be more expensive than the internal one.

The Auger gravel pack screen from Baker Sand Control offers an alternative to Internal Gravel Packs (IGP) and External Gravel Packs (EGP). In this case, the perforations or open hole are initially prepacked, before the Auger screen is screwed into place. This should minimise impairment as the gravel is placed when the perforations or open hole are at their cleanest.

Generally, it is accepted that gravel packs control sand production most effectively, and are the preferred option in cases where no sand production can be tolerated at all or where the cost of remedial work would be excessive, e.g. subsea completions.

The last technique which also leaves a screen in the wellbore is the fracpack. The main advantage of this technique is that the fracture extends beyond any damaged zone and so stimulates the well, potentially giving very high PI.

However, all these techniques leave a screen in the hole. The small ID of these completions means that access below or logging across these intervals will not be readily possible. This may significantly increase the life cycle costs of the well. Thus, the preferred scenario would be to leave an unobstructed wellbore, so that the intervals can be individually selected, if required.

5.2 Chemical options

One sand control option which satisfies the unobstructed wellbore criterion is chemical sand consolidation. PIs tend to be on the higher side, but the main drawback is that only relatively short intervals can be treated at one time. To overcome this, a straddle packer can be used to selectively treat multiple zones in one trip. Up facing wash cups ensure that the upper zones do not sustain losses while the lower zones are being treated.

An extension of this technique has been a one trip system, where the zones were perforated and consolidated in one trip. This minimises the exposure of the formation to wellbore fluids, in the time between perforating and consolidation. The technique also saves rig time, which should reduce costs. Experience with sand consolidation shows that some sand production may occur when the well is initially opened. Afterwards, the sand rate drops back to low levels.

5.3 Chemical/mechanical options

If a formation has been producing without sand exclusion, and then fails, cavities may exist. These cavities could be filled by prepacking with resin coated gravel. Usually, there is excess gravel in the wellbore, which has to be drilled out. The disadvantage of this type of approach is that the formation remains loose and so material may flow into the gravel prepack and plug up the pores in time.

If chemical sand consolidation is carried out when cavities are present, the chemicals may not be uniformly injected around the cavity walls, into the formation. Also, the formation around the cavities, may be dilated with few contact points between the sand grains, which would lead to poor consolidation strength after treatment. Thus, the cavities should be prepacked prior to a chemical consolidation treatment. The resin would then consolidate not only the prepacked gravel, but also the formation around the cavity, stopping this material from flowing into the prepack. This prepacking-consolidation technique could also be applied to new zones, if excessive fill has been seen after perforating or when perforations have been washed.

Similarly, a fracpack could be completed without a screen in place and subsequently consolidated. Resin coated proppant has been used in the past to try to control proppant back production from massive hydraulic fractures. Unfortunately, there have been a number of cases where the resin coated proppant has been produced back. The failures could be due to the resin interacting with the frac fluid, which could degrade the resin properties. Alternatively, the proppant may be too poorly packed together to yield a good consolidation perhaps because the fractures close more slowly than the resin cure rate.

The advantage of carrying out a chemical consolidation after fracturing, would be that the treatment could be carried out, after the frac had closed. Also, the epoxy resins used for chemical consolidation, are more robust and durable than the phenolic and furan resins used for coating proppant. Phenolic and furan based resins have been shown to degrade during stress cycling, due to their brittleness. Epoxy resins are much more flexible than the phenolics and furans and hence should withstand stress cycling better.

5.4 Sand control conclusions

• Most forms of sand control applied in conventionally sized wells can be applied in slim hole wells.
• Mechanical options, where a screen is left in the wellbore afterwards, limit the possibilities for future workover or remedial action, which may increase life cycle costs. Large reductions in productivity are seen when gravel packs are installed using current technology, whereas fracpacks can stimulate production.
• The use of chemical consolidation allows the wellbore to remain unobstructed, while productivity remains high. Also, deep penetration charges can be used to enhance productivity.
• Alternatively, in the case of cavities or remedial sand control, prepacking or fracpacking without a screen in place, followed by sand consolidation could also be considered.
• Other options, which could be applied for longer intervals, involve using resin coated gravel/proppant for fracpacks or for prepacking, but these should be considered when the reliability of the resin coated systems improves.

5.5 Sand control recommendations

The preferred option for sand control in slim hole wells would be chemical sand consolidation, after the production liner has been perforated with deep penetrating charges. The maximum perforated interval would be 3 m or less to allow reliable treatment of each zone and to allow access for remedial action if required (e.g. water shut-off). The tools are available for carrying out multiple sand consolidations so completions can be readily achieved with a series of 3 m perforated sections all consolidated in one operation.

6 Outflow performance

It is widely recognised that tubing size must be optimised on a case by case basis in consideration of well inflow potential, oil viscosity, GOR, BSW, depth etc.

Tubing outflow in the case of 3 1/2" tubing, can achieve production rates of 4000-6000 b/d at the start of production (0% BSW). At 90% BSW, production rates of approximately 1500 b/d are possible.

7 Artificial lift

7.1 Introduction

In principle, all forms of artificial lift commonly used in oil wells can be applied in slim hole wells. Options available include gas lift, coiled tubing gas lift, electric submersible pumps, rod pumps, Moineau pumps, jet pumps and hydraulic pumps. The casing and completion scheme must be compatible with the required artificial lift system. In general, pumping systems must be set in the casing above a 3 1/2" liner, so one must ensure that head loss below the pump is economically acceptable. Installation of artificial lift systems, other than gas lift will generally preclude operating the well as a "monobore".

7.2 Gas lift

The completion configuration selected will directly impact the gas lift options available.

Ccoiled tubing equipped with gas lift valves can be used to effect gas lift in monobore wells. The obvious drawback of this system is that the coiled tubing must be removed prior to conducting any through tubing workoversMonobore> = 65/8"31/2"WL retrievable gas lift valve (side pocket mandrel).All common vendors are able to provide side pocket mandrels which will accommodate 1" gas lift valves and still offer a 2.813" drift diameter.Non-Monobore51/2"27/8"Otis and other vendors can supply side pocket mandrels which will accommodate a 1" gas lift valve and offer a 2.347" drift diameter. This system may be suitable in cases where monobore completions are not warranted and 2 7/8" production tubing is desired

7.3 Electric submersible pumps

Electric submersible pumps (ESPs) suitable for slim hole applications are available from standard vendors of this equipment, e.g. Centrilift now offers their 338 series pumping systems for use in 4 1/2" casing suitable for lifting production rates of 550 to 1700 bbl/d. If 5 1/2" casing is used, pumps such as Centrilift's 400 series are available which are suitable for lifting rates between 180 and 6800 bbl/d.

If an ESP is used, the well will no longer be a 'monobore' as through tubing workovers cannot be conducted through the ESP. The ESP would have to be located in the casing above the liner.

7.4 Rod pumping

In principle, slim hole wells may be rod pumped using standard rod pumping equipment. Three options for rod pumping exist:

1. a conventional tubing or insert pump set in the tubing above the liner,
2. a conventional tubing or insert pump set in a tubing stinger, or
3. a casing pump installed in the liner.

In most rod pumping applications, it is advisable to have an open annulus to allow gas to be produced up the annulus thereby precluding pump problems. Also, the annulus acts as a buffer to collect oil while the pump is on a down stroke. An open annulus can be achieved with both a pump in the tubing or in a tubing stinger.

A casing pump should only be considered as an option when the PI of the well is very high and pump capacity is limiting well deliverability.

7.5 Other pumping systems

Depending on specific well conditions, other pumping systems such as Moineau pumps, jet pumps and hydraulic pumps can be easily adapted to slim hole wells.

8 Slim well completions - Conclusions

• The primary drive with slim hole wells is to achieve cost benefits associated with slim hole drilling.
• It is possible to complete slim hole wells with 3 1/2" production liners. A wide range of tools and equipment is available which can be adapted to meet the specific needs of various developments.
• The benefit of drilling cost savings must be compared to potential adverse affects in terms of well productivity and operability. There is probably a range of well applications, such as the Gbaran wells, where well cost savings during drilling and completion will overwhelm any adverse affects associated with producing and operating slim hole wells. Clearly, the cost benefit of slim hole wells must be assessed on a case-by-case basis.
• Specific operating experience and continued commitment is required to maximise the benefits of slim hole development wells.