One of the applications of slim hole drilling technology is for low cost exploration and delineation wells. Slim wells from fixed rigs (land/jackup/swamp) can be drilled using the down-sized conventional or the continuous coring approach, but the testing procedures and tools are in principle similar.

As with full sized wells, testing may be conducted in open or cased hole. The monobore completion concept applied to slim wells allows a well to be completed with a 3 1/2" or smaller liner at minimum additional expense. This could move the economic balance of production testing towards cased hole testing, although there is some evidence that small holes are more stable and more in gauge than larger holes, which would tend to favour open hole testing.

Planning horizontal wells requires knowledge of the vertical distribution of flow potential from exploration wells. The improvements in resolution of reservoir and geological computer finite-element models of the subsurface complement this trend.

In some cases where traditionally two or three intervals have been tested with spinner runs to estimate the initial flow distribution, a monobore approach would allow a series of short-duration tests of small intervals, followed by one or two longer tests to assist in extrapolating the results of the short tests. This would also enable some of the small intervals to be tested at high drawdown to assess sand production potential. Limited injectivity, acid treatment and other tests could also be done.

For small minimum space rigs, provision of space for surface production test equipment presents some problems. Providing space for conventional production test equipment, burning system and appropriate hazardous areas as well as the rig would require substantial location enlargement.

1 Downhole tool selection

Obviously, as borehole diameter is reduced there is progressively less cross-sectional area available to distribute between the test tools, the flow area and required annular clearance. The additional risk of mechanical failure must be included in the evaluation of whether to use a slim or conventional well. If the borehole diameter is reduced below "standard sizes", it is increasingly critical that the potential well test conditions, objectives, tools and equipment and operating practices be thoroughly pre-planned prior to spudding the well to ensure that required well objectives will be met.

2 Listing of available downhole test tools for slim hole applications

Halliburton

Schlumberger

Baker

TAM International

2.1 Production logging

The availability of production logging tools is not adversely affected by the use of slim wells as they have traditionally been designed for 2 3/8" tubing upwards. Consequently most production logging tools are available in 1 11/16".

3 Potential configurations

3.1 Monobore completion

The 3.5" monobore completion is one option suitable for testing a slim well where coiled tubing (or a small work string) is available. The monobore completion also results in a maximised flow area so risks associated with solids production and plugging are mitigated. Flowing the well to establish the rates at which sand production starts may be easier with this completion. One advantage of this type of testing procedure is that the completion tubing is only run once even when multiple zones are tested; if desired testing can be conducted after the rig has been released.

A base testing procedure for testing such a monobore completion is:

Test procedure

1: Run 3.5" monobore completion and pressure test.

2: Run coiled tubing below interval to be perforated. Pickle tubing with acid by circulating through coiled tubing. Displace well to clean completion fluid of appropriate density. If additional drawdown is required:

2.1: spot a diesel cushion

2.2: swab

2.3: pump nitrogen and use of circulating device

2.4: use nitrogen and coiled tubing.

3: Perforate underbalanced with wireline conveyed guns.

4: Install pressure temperature recorders on Otis L Lug Type Bomb Hangers and Otis LO Shock Absorber (for example, equivalent equipment is also available).

5: Conduct production test. If required, to mitigate wellbore storage effect, run Schlumberger PRST (or equivalent) in landing nipple to effect downhole shut in.

6: Retrieve wireline tools from well.

7: If subsequent shallower zones are to be tested, abandon zone with bridge plug (and cement if required). Then repeat steps 2 through 6.

Notes:

1.Another potential advantage of this technique is the lower zone can be abandoned through tubing without 'killing' the well. This means that if the well cannot be bullheaded, the lower zone can be abandoned and then the tubing circulated and/or lubricated dead.

2.The test may be conducted through the rig BOPs or using a small Xmas tree.

3.If the location is small then the rig may be moved off location, production test equipment installed, and the test supported by an electric line unit.

3.2 "Conventional" cased hole test

Tool strings can be used to effect a "conventional" cased hole test using a permanent packer set in a 5" or 5.5" casing set above a 3.5" production liner. A base test procedure would be:

Test procedure

1: Run bit and scraper to below test interval. Displace well to completion brine of appropriate density to overbalance well.

2: Perforate with wireline conveyed perforating guns.

3: Set Baker FA-1 (or equivalent) packer in 5 or 5.5" casing.

4: Run Schlumberger PCT-G tool string (or equivalent).

5: Conduct well test.

6: Bullhead well dead. Pull seals from packer and reverse remaining fluid from well.

7: Repeat steps 2 to 7 as required.

Variations of this test string include the use of 2" OD TCP guns and retrievable packers with potential for underbalanced perforating.

3.3 Test tools within 3.5" liner

1.75" OD tools and equipment for testing can be used for 3.5" liner. However the inner diameter may be very restrictive to flow and prone to plugging.

3.4 "Conventional" open hole test

A 3" OD test string is available for the 4.125" and 4.375" open hole diameters; equivalent flow area diameter of this test string is 0.50". A 3.875" OD tool string is available for 6" hole sizes and has an equivalent flow area diameter of 0.62". Depending on hole conditions, it may be possible to safely run the 3.875" OD test string into a 4.75" open hole.

3.5 Open hole test with inflatable straddle packers

It is possible to  selectively test horizontal wells using TAM International Model J straddle packer below conventional testing tools. It is feasible to run the TAM-J straddle below full opening tools such as the Halliburton Omni Valve and LPR-NR. Where straddle testing capability is required this type of test configuration should be considered. Baker list a 2 1/8" OD straddle test string for 3 3/8" open hole.

3.6 Possible artificial lift methods for production tests for low pressure wells

For testing wells incapable of significant natural flow to surface the use of a drilling Moineau motor as a temporary production pump may be considered. The motor is run above a packer on a (DP) test string. The packer is set and the drillstring rotated. The oil is pumped up the DP and through the kelly/power swivel, or special production swivel. Recording pressure and temperature gauges may be run beneath the packer. The system can provide a pressure differential of several hundred psi for over a week. It is particularly applicable for heavy oil reservoirs, where the alternatives are prolonged swabbing, or continuous nitrogen lift. The small motors (e.g. 2 3/8" OD for drilling 2 7/8" hole) and tubing work string may already be on-site for drilling contingency hole. It should be noted that the drawdown achievable is limited by increasing torque as the friction between stator and rotor increases with drawdown.

Jet pumps powered by the mud pumps are also a possibility. The use of jet pumps will make measurement and recovery of well production more difficult.

If a supply of gas is available (or nitrogen for a limited duration test), gas lift is also a viable option. CT can be utilised either with injection down the coil or down the annulus and may utilise gas lift valves run on the CT.

3.7 Test strings

For down-sized conventional drilling most small DP connections will be double shouldered (2 7/8" DP used for 4 1/8" or 4 3/4" hole). This should provide a gas tight test string. For smaller contingency holes Hydril tubing (which is multi-shouldered) is often used as drillpipe and this can obviously double up as a test string.

4 Surface equipment

4.1 Introduction to surface equipment

If the production test involves prolonged flow to surface, a well test set up is required. These are normally fairly large, especially when the appropriate hazardous areas are included.

For offshore rigs surface equipment design, specification and operation is usually well established and few changes can be expected in the short term. In mature areas, where there is usually significant offset experience of reservoir flow potential, often production testing is eliminated, or conducted after the well is hooked up to the production facilities.

However, for rigs with a small foot print which are now being proposed for land and swamp drilling in environmentally sensitive areas, or for remote area exploration drilling, the area required for the production test equipment may be two or three times the size of the rig.

The scope for reducing the surface equipment and environmental impact from burning the well effluent is limited unless the requirement for flow testing long intervals can be eliminated. A sequential production test of small intervals at lower rates using a monobore concept holds can be considered. Such test would mean that the production test would last for longer, but the resultant rig and production test equipment size, and hence mobilisation and daily cost would be smaller.

From a safety perspective; while the exposure time when live hydrocarbons are being handled on surface is longer and the number of tests greater (increasing the risk of a leak), the system hydrocarbon inventory, momentum, and open flow potential in the event of a leak would be smaller. Burner radiation would also be reduced.

Thus, for a given well or campaign, where it is desired to minimise the size, mobilisation, cost and environmental impact of well testing, the specification for surface systems for flow testing should only be drawn up after a draft subsurface production test programme has been made. This in turn has to be based on a clear set of objectives from the reservoir engineers and production technologists at the well proposal stage. The objectives should be ranked and costed. These objectives and test programme should then be iterated with various alternative surface equipment set-ups.

4.2 Potential future developments in surface facilities for slim wells

As indicated above the design and specification of surface facilities is driven by, and must be closely integrated with, the subsurface test programme. A number of factors could be considered . These include:

4.2.1 Burners

If well effluent is disposed of by burning then the location could be extended to provide a burn pit. Alternatively two offshore type burners could be mounted on tripod masts on opposite corners of the location, and the downwind one used. The small land rigs will have a location area about half of that on an offshore semi-submersible, so area classification, and heat radiation may be problematic. Dropout of unburned well effluent is a fire, slip, and health hazard. Impurities such as H2S in the well effluent would complicate things further.

For some areas enclosed burners may be required. Low rate flares from choke manifolds have been mounted on the top of derricks. Some Self Elevating Workover Platform boats in the Middle East have had test burners mounted on booms supported by hydraulic cranes. These can be oriented downwind to minimise radiation.

Venting of unburned gas, apart from being environmentally unsound, can present a risk of asphyxiation and when ingested by internal combustion engines can create "runaway".

4.2.2 Tankage

An alternative to burning liquid hydrocarbons is to store them. Obviously hard tanks can be used, but these tend to be heavy. One alternative that needs further investigation is to use rubber pillow tanks similar to those used by the military to store aviation and other fuel in. For live hydrocarbon service, additional venting and pressure relief valves may be required. Such tanks could be used to store well effluent until it could be disposed of by burning, re-injection down the well, or trucking off the well site.

4.2.3 Multi-phase metering

In recent years considerable progress has been in multi-phase metering.

4.2.4 Production testing with the rig off site

With slim wells the incremental costs of completing the well with a monobore completion are relatively small, and as an alternative to extending the location, the option of designing the well to be flow tested with the rig offsite may be attractive. If a CT unit is available then this becomes relatively easy. If one is not available it may be possible to conduct the test with only a small pump, kill fluid for bullhead killing, and a well effluent handling system (tanks/burner/etc.). Clearly this is not suitable for all wells, and the rig may have to return for abandonment.

5 Conclusions

• Use of slim hole drilling for exploration and appraisal is feasible as subsurface equipment suitable for slim well testing is currently available from a range of service companies.
• Contingency available in the event of problems during testing a slim well completion is limited and this should be fully assessed when deciding to use slim well technology for exploration and appraisal wells.
• 5.5" production casing and 4.75" open hole is recommended as a wide range of 3.9" OD test tools are available.
• A 3 1/2" monobore completion offers an effective approach to production testing in some circumstances.
• The surface equipment for slim well flow tests is currently conventional, but possibilities exist for down-sizing.