07. Operational recommendations

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1 Surface

1.1 Anti-pollution measures

It is possible that hydrocarbon pollution of surface waters could occur during production testing. A spill is likely to be limited as the well and production test equipment are constantly monitored and rigged to enable instant closure of the well. Anti-pollution equipment and materials to handle oil pollution must, however, be readily available during well testing operations.

Disposing of crude oil through burners may cause pollution. This is not always detectable at the offshore location (strong currents, adverse weather conditions). Helicopters are usually available in an area where well testing occurs and should be used during routine or special flights, to survey the area around the rig where well testing is in progress, to detect possible spillages.

Although the best way to counteract oil pollution is physical removal of the crude, a practical alternative is the use of low toxic detergents. These dispersants work by changing the interfacial properties of oil and water so that mild agitation will break up the oil layer into very small droplets which will be dispersed in the upper layers of the sea where natural processes such as evaporation, dissolution and biodegradation remove much of the oil. Supply/Standby boats should have a quantity of this material and spraying equipment on board during well testing.

1.2 Disposal of hydrocarbons

The pilot flame on the crude oil burner is normally supplied with bottled propane gas, purchased locally.

When the rig has no sprinkler system or the system is inadequate, it is advisable to arrange for fire hoses to keep equipment and hull wet in the vicinity of the flame.

The waterlines to the burners should be flushed before the test, with the spray nozzles at the burner removed, so that rust particles will be removed.

It is good practice to test both burners, by pumping and burning diesel oil, before the actual production test starts. For smokeless burning, water should be injected into the flame at an oil/water ratio of 1:1.2.

1.3 Hydrate prevention/antifoam injection

In the presence of free liquid water, hydrocarbon gases and natural gas components can form a solid snowlike substance called "hydrates". Methane, ethane and propane readily form hydrates, butanes less readily.

Pentanes and heavier hydrocarbons do not form hydrates and tend to inhibit hydrate formation in the other compounds mentioned.

The formation of hydrates will occur in the presence of free water under specified pressures and temperatures. In general, the lower the temperature and higher the pressure the more readily they are formed, but water in the vapour phase does not form hydrates.

Hydrates may accumulate in the flow system where the gas flow changes direction/velocity, e.g. in bends, valves, reducers, thereby rendering valves inoperable and blocking the gasflow.

The conditions for hydrate formation, temperature and pressure of the gas flow, may be estimated using the gas analysis and hydrate prediction curves, which are based on vapour solid equilibrium constants. More rigorous calculation methods can be found in the NGPSA Manual or in computer programmes.

Where cooling of the gasflow occurs there is also a possibility of hydrate formation, e.g. a pressure drop over a choke or other restriction causes a temperature drop; this can also occur in a transport line or any other point of the gas handling system.

The presence of non-hydrocarbons in natural gas may have an effect on hydrate formation. N 2 has hardly any effect, CO 2 has a pronounced effect in the formation of hydrates.

Hydrate formation can be suppressed by adding freezing point suppressants to the free water containing gas flow. The most convenient soluble material used for this purpose, when production testing exploration wells, is methanol. Glycol can also be used, but in the presence of H2S methanol is preferred as glycol forms a highly corrosive sludge in combination with the gas. Both fluids are flammable, especially methanol, and should be treated with care, avoiding contact with the eyes.

Natural gas is usually assumed to be saturated with water vapour (i.e. in equilibrium with free water) at bottomhole temperature and pressure. Any free liquid water that is produced with the natural gas, in addition to the liquid water that separates due to changes in temperature and pressure, will also require hydrate suppression. For production operations it is assumed initially that the well does not produce free water.

To prevent hydrates forming, after the choke, heat the gas immediately after the choke so that any formed hydrates are melted. When a heater is not available, methanol should be injected before the choke. On floating rigs it is advisable to inject methanol at seabed level to protect the tubing riser from hydrate formation.

1.3.2 Antifoam injection

Antifoam chemicals eliminate foam in gas-oil separators, thus preventing oil carryover and increasing the throughput. High viscosity Dow Corning 200 fluids are recommended, diluted in either white spirit or diesel oil, and applied ahead of the gas-oil separators, for more efficient dispersion and metering. It is recommended that Dow corning 200/12,500 Cst is available during production testing. The addition of minute quantities (0.001 - 0.025ppm) of anti-foam agent in the separation inlet lines has resulted in 40% increases in throughput.

The recommended quantity required for successful treatment during well testing is 0.01ppm.

1.4 Guidelines for opening up a well

The following guidelines should be observed (see well programme for details):

1.Never open up a new zone during the hours of darkness.

2.Inform the company toolpusher of the plans.

3.Check lines to burner are open and pilot flame on.

4.Ensure that safety shut-in system is operable.

5.Open up the well on a 16/64 adjustable choke. Observe the well for a reasonable time. Do not bean up too quickly.

6.As soon as the first well effluent appears at the surface, a check should be made for H2S. H2S is a colourless and transparent gas and is flammable. It is heavier than air and may accumulate in low places. When H2S is present special alarm and safety precautions have to be taken and all operations such as sampling, blowing down pressures etc. should be carried out according to special instructions and procedures.

A concentration in the air of 100ppm H2S deadens the sense of smell in 3 to 15 minutes and a concentration of 500 ppm kills a person in a few minutes.

7.Sometimes the well will unload very slowly. In order to gauge low rates, the time to fill a bucket is measured. A record of the filling time will give an indication of the well behaviour and the total volume produced. This unloading can take a very long time (10 hours is not exceptional).

8.Try to avoid producing the well direct into the gauge tank. The danger is that gas might break through suddenly and because the flame arrester on the gas vent of the tank cannot handle large volumes of gas, the pressure in the tank will build up and may cause the tank to burst. (A few inches of water column pressure is sufficient to blow the roof off of a square shaped gauge tank).

9.Bypass the separator until clean fluid is being produced. However, keep a good record of bean size and production time so that the quantity of oil produced, during separator by-passing, can be calculated later. Take samples for BS&W determination at the flowline manifold upstream of the choke or at the Xmas tree.

1.5 Bringing in marginal wells - jet pumping, coiled tubing, etc.

It is possible that marginal wells will not come in, even by circulating the tubing contents to diesel oil. Various methods are available such as swabbing, jet-pumping, gas bombs, coiled tubing etc. Due to the temporary nature of the facilities for a test set-up, it is not normal to utilise swabbing and gas bombs either due to their hazardous nature or their ineffectiveness. Jet pumping has been used with success, but is dependent on supply of adequate quality power water etc. As a coiled tubing unit is nowadays reasonably inexpensive and usually already on site for other operations, e.g. acidising, this can effectively be used to bring in the well and is the preferred route.

2 Subsurface

2.1 Wireline operations

1.Slickline wireline operations can best be carried out with either the wireline unit positioned on the drill floor or on the catwalk. When positioned on the drill floor, it provides easier access to the well and simplifies communication between wireline operator and assistant. However, the following factors must be considered.

a)There should be ample space on the drill floor so that the unit can safely remain in place throughout the duration of the test.

b)The unit must have an air or handstarter, spark arrester and rig saver device, i.e. certified for zone 1/2 operations.

In all other situations, the wireline unit should be installed on or next to the catwalk. Walkie-talkies should be used for communication.

2.Wireline unit speed should be 2800-3000 ft/min with a full drum to ensure effective jar-up action in deep deviated wells.

3.Though many operations can be performed with the wireline system, it is essential to keep the number of wireline runs down to a minimum during production testing in order to minimise the chance of problems during wireline operations.

4.It is generally not advantageous to leave wireline in the well during bottom hole pressure surveys. Where possible, permanent pressure and temperature monitoring equipment with a surface read-out should be designed into the completion string. If it is necessary to run and set subsurface recorders, soft release running tools and instrument hangers with appropriate locks have been used successfully.

5.Pulling a set of recorders from the derrick floor or spider deck into the lubricator requires extreme care. If the dogs of the instrument hanger inadvertently catch behind some obstruction during handling, the pressure recorders will be released and may cause injuries to personnel and/or fall through the spider deck.

6.When gradient surveys are necessary, it is advisable to use inhibitor on the wireline. Inhibitor can be applied by injection into an injection sub fitted in the lubricator. Flowing bottomhole pressure surveys have been made with the wireline in the hole using sufficient weight, e.g. lead filled stems, to keep the instruments down against the well flow. Decrease of weight, shown by the wireline weight indicator, is a doubtful check on whether sufficient weight is applied. Observed weight loss implies that the pressure recorder may not be recording at the planned depth but higher up, or worse that the wireline may have been partly blown up, looped or even broken.

7.It is common practice to run wireline through open surface controlled tubing retrieval subsurface safety valves; however, care must be taken to ensure that the control pressure is some 1500psi higher than the closed-in tubing head pressure to keep the SSSV open.

8.All components of the toolstring, stems, jars, wireline head etc., must have fishing necks, so that a disconnected string can easily be fished by wireline methods.

9.After make-up V-packing (used on test plugs, subsurface safety valves, etc.) should have a diameter slightly less than that in which it is to pack-off. Pressure over the V-packing will expand it and ensure tight pack-off. V-packing material (e.g. Teflon, Viton) should be resistant to the influence of CO2, H2S, etc. to avoid swelling/destruction.

10.O-rings, and back-up rings used in conjunction with O-rings, must also be resistant to CO2, H2S, etc. to avoid disintegration. Special elastomers are required when the temperature will be above 250-300°F (K-Ryte).

11.No-go nipple and Test tool can be used for pressure testing of the tubing string; the wireline can be left attached to the test tool while pressure testing. Tubing pressure tests have been made with X-equipment; however, several cases of rupturing X-mandrels, while pressure testing at 2500-3000 psi, have been reported. Although the X-line is improved in this respect it is recommended to use the RN nipple and test tool.

12.In a newly completed well, it is good practice to run a tubing end locator to "tag" bottom and determine the location of the tubing shoe prior to routine wireline work.

13.It is good practice to cut the last 30-50 ft of wireline at the start of a new series of wireline jobs. The wireline operator must ensure that no one is in the path of the line when cutting it. The cut line will coil up quickly towards the wireline unit and could cause injury to any one in its path.

2.1.1 Logging during high flowrates (electric line)

When logging operations need to be carried out in high fluid velocity wells and it is necessary to leave the tool stationary in the well for extended periods of time, the following recommendations should be considered:

1.Position the tool, where feasible, below the bottom perforations.

2.If this cannot be achieved, position the tool above the top perforations but keep tools away from the tubing shoe in order to avoid possible turbulent areas.

3.Never leave the tool in front of the producing interval. It may permanently damage instruments such as gradiomanometer, flowmeter, etc.

4.It is possible to keep the toolstring under tension (and thus motionless) by making use of a tubing-end locator at the bottom of the toolstring. In this case, a perforated joint should be installed above the tool.

5.Do not close the BOP rams on the cable, otherwise the tension monitoring capability will be lost.

6.Keep the well shut in, when running-in, in order to avoid problems running through restricted sections.

7.Never enter the tubing shoe with the equipment when the well is flowing at high rates.

8.In order to minimise dyCompanyic effects and detrimental shock waves on tubing restrictions, open the well very slowly, by 200 to 500 bbls/day per 5 min for casings ranging from 41/2 in to 95/8 in. Special caution should be exercised when opening up oil wells with a gas cap.

9.Before pulling out, shut-in the well in order to enter the tubing shoe and pass the restrictions. If it is undesirable to shut-in the well, the production rate must be limited to a fluid velocity of less than 30 ft/s with the toolstring passing through the smallest restriction in the tubing string.

2.2 Tubing/connections

1.It is good practice to make a sketch of the tubing string composition showing inside diameters of all components. This will assist in determining limitations for wireline work and thus avoid embarrassing situations once the string has been run.

2.Prior to running the completion string, the components must be checked/tested at the surface by:

a)Drifting (to ensure sizes used are correct, no fabrication mistakes or damage have been incurred).

b)Pressure testing.

c)Simulation of downhole operations, e.g. open/close sliding side doors, operate subsurface safety valve, operate pinned components and redress them.

3.Tubing must be clean internally to make successful wireline work feasible. Air operated tubing cleaners or power brushes can be used for removing scale, dust etc. API modified thread compound should be applied sparingly, to pin ends only, while running the joints. Excessive use of pipe dope can permit it to build up inside the tubing which will severely hamper or even prevent wireline operations.

4.Tubing must be drifted or go-devilled and threads inspected to eliminate damaged joints incurred during transport or handling on previous jobs, e.g. by powertongs.

5.The torque used while making up tubing joints should be strictly controlled to prevent damaged joints and/or leaking connections.

6.The Completion string must be tested hydraulically. If the aforementioned precautions have been adhered to, it is usually superfluous to use inside - or outside - tubing testers (Hydrotest and Gator Hawk respectively).

7.It is normal practice to pressure test the tubing with a wireline plug set at the bottom of the completion string. This method has been successfully performed on many occasions.

a)All joints of the tubing string that are used for well testing must have thread-protectors fitted before/after use in the well. Supervisors should ensure that no thread-protectors are lost. An adequate number of spare thread protectors should be available with each tubing test string. DRILLTEC protectors are preferred.

b)When the tubing will not be used for a period of more than six months, it is recommended to protect the tubing by spraying internally with Shell Ensis 210 plus 25% Shell Cyclo Sol 51 and externally with Tretolite KP-94 Black material.

It is advisable to contract out tubing inspection and running services to the supplier of the pipe. Vallource , for example, have such a service and this strategy has shown an improvement in number of rejects and success rate.

2.3 Sliding side door

1.The sliding side door (SSD) positioning tool has spring-loaded dogs which locate in the sleeve to be shifted. The dogs, during running in/out, are in contact with the tubing wall and are exposed to excessive wear if the shifting tool and tubing are of the same nominal size. Shifting of the sleeve may then become difficult/impossible. It is preferable to incorporate a sliding side door, which is smaller in nominal diameter than the tubing string. Faster running/pulling of the shifting tool is then an additional advantage especially when wireline work has to be carried out in mud.

2.Prior to shifting, the pressure differential over the SSD should be reduced, if possible, to a minimum to facilitate smooth shifting, to avoid heavy jarry on the sleeve and prevent blowing up of tools.

3.Circulating velocities through the SSD should be restricted to 3 or 4 bbl/min to reduce the possibility of washing out the slots of the SSD.

4.Every SSD should be checked, for proper operation and inside diameter, on the surface prior to running the completion string. Particular attention should be given to used SSDs which should, in addition, be redressed/tested prior to running in with the completion string.

2.4 Completion fluids/mud

To promote trouble free wireline operations the well should be circulated to a clean fluid of low viscosity.

Brines are preferred because their densities can be adjusted within a wide range. For densities in excess of 1390 kg/m3, mixed brines containing bromides are required which are very expensive and must be handled and maintained with great care. In these cases, it is worthwhile to consider the use of powdered, preferably acid degradable, solid weighting material suspended in a viscous liquid. A stable fluid can be made in this manner provided it is properly formulated and prepared.

This cannot always be achieved in remote drilling locations and, therefore, reversion to completion in mud and minimum wireline operations should be considered. Accumulation of coarse suspended matter in completion fluids will jeopardise wireline operations and should be avoided by proper fluid handling - a high VISCOSITY can limit or even prevent jar action. In some cases, often due to cost and/or transport problems, an exploration well has to be completed in drilling mud. Wireline operations can be carried out under these circumstances, but take more time and are more difficult to perform (e.g. slow running in, reduced jar action, less response at surface).

It should also be realised that circulating/displacing drilling mud through a SSD needs higher pressures and so causes rapid cutting out of the circulating parts of the SSD.

2.5 Circulating/kill valve

If during tubing pulling operations, the well starts to flow or loss of liquid level occurs in the well, a circulating valve is immediately required. To cope with such situations, it is necessary to have a circulating/kill valve on the drill floor which can be screwed on the tubing immediately when flow or losses occur. The circulating valve should have a connection suitable for circulating purposes, e.g. 2 in. Weco Figure 1502.

2.6 Annulus operated valves

For reasons of simplicity, practicality and safety, these valves are used in the tubing string to allow activation of mechanical parts. This is accomplished by pressure pulses of varying intensity and duration. This is further discussed in Section 6.

2.7 Tubing string operated valves

Valves that are operated by tubing set, down weight and by picking up the string, are sometimes used in DSTs, e.g. Ful-FLO hydraulic circulating valve.

2.8 Packers

1.Check at an early stage that the packers are the correct size and that the bore is compatible with the seal assembly. Remove the flapper at the bottom of the packer if one is installed.

2.Ensure that the logging contractor has the correct adapter kits for setting the packer.

3.Permanent packers have been milled out and retrieved. Company has reported an average of 6hours required to mill/retrieve Baker Model D and DAB packers from about 9000 ft, on 21 jobs, with 100% success ratio.

2.9 Stabbing shoe

Several well test reports have mentioned damaged mule-shoes after stabbing the production string through the permanent packer, resulting in extra wireline work to swage open the mule shoe to make the passage of wireline tools/perforating guns possible. Damage can be avoided by using a barrel shaped stabbing shoe.

 

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