06. Equipment preparation


1 Introduction

It is usual to contract out Well Testing Services, including the inspection, testing, drifting of equipment in base workshops and on site.

The effort and time spent to ensure the integrity of each individual component used downhole and on surface will impact on the success of a well in minimising downtime. The thorough inspection on site, before and after use is strongly recommended.

2 Subsurface equipment

2.1 Tubing

When testing to 5000psi, it is generally sufficient to use tubing that is the preferred type used in most completions, e.g. 31/2" New Vam 9.2 lbs/ft L80. In pressures beyond 5,000 psi, the 31/2"Hydril PH6 15.8lbs/ft C95 is preferred, due to the halved number of connections (versus threaded and coupled) and its historically proven make and break repeatability.

Due to the uncertain nature of well testing in terms of pressure and temperature, it is recommended that the chosen tubing connections be of a type tested to API 5C5.

2.2 Accessories

Each accessory has critical design dimensions and is put in string to carry out a specific function. For reasons of simplicity, it is important to incorporate only those accessories that are required to perform a function, e.g.XNlanding nipple to land ameradas. Back-ups are not required due to the temporary nature of the string.

2.3 Xmas tree

The term Xmas tree here is taken to mean generically, and includes subsurface and surface Test Trees. The choice of tree will usually be dictated by the pressure regime it will operate in the location of the well. Most land operations can tolerate a conventional X-tree. A floater for example will have a subsurface and surface test tree complete with swivel to accommodate wave and tide motions. As these items are the principal pressure vessel that would contains full well pressure in any ESD situation, extreme care must be taken in its selection, preparation, testing, transportation and ESD accessories, e.g. actuators.

3 Surface equipment

A list of equipment downstream of the Xmas tree to the burners is given in Section 2. It is generally the norm to hire such equipment from the principle contractor awarded the testing contract. Particularly in Single String Ventures, all equipment is loaded on the rig prior to being moved on site. It is important to carry out full W.P. (working pressure) tests already at this stage, as there are no time constraints, personnel safety is enhanced and any defects can be rectified in time. It is also possible that equipment and rig deck space are a mismatch in ensuring recommended safe distances between, for example, separators and heat exchangers. Such problems can only be rectified if time is not a constraint.

4 Certification and documentation

It is increasingly becoming mandatory to comply with Governmental legislature pertaining to methods of ensuring that tools, equipment and materials conform to international or regional manufacturing standards such as BS5750 (part1), ISO9001, etc.

In the main, API have existing standards that cover virtually all surface items, e.g. separators. Very little however exists for subsurface items, e.g. nipples, SSD's.

It is recommended that all pressure vessels be certified for use by accreditation bodies such as DNV, Lloyds, etc. on a regular basis, e.g. 5 years on separators. It is expected that all such certification and documentation will be readily available for verification if called upon prior to a well test.

5 Workshop

Most OPCOS have excellent workshop facilities that are able to handle all types of preparatory work required to be done prior to shipment to site. These would include functional checks, drifting, hydrostatic testing of assemblies and components, etc.

As far as is practical, equipment should arrive on site at the rig, in a ready to run/use condition where only final measurements, tallying, checks are made.

6 Material standards

6.1 Types of corrosion in oil and gas production

Corrosion problems which may occur in drilling for and production of oil and gas may be caused by:

1.sweet corrosion;

2.sour corrosion.

6.2 Sweet corrosion

Sweet corrosion is caused by carbondioxide (CO2) which dissolves in the accompanying water phase and lowers the pH results in a highly corrosive environment. It can cause either a uniform type corrosion or pitting (ringworm corrosion). Carbon dioxide corrosion is unlikely to occur when the CO2 partial pressure is lower than 7psi. The partial pressure is determined by multiplying the volume percentage of CO2 by the gas pressure in the system.

Since production testing is usually of short duration, sweet corrosion is considered of little importance here.

6.3 Sour corrosion

Sour corrosion is caused by the presence of H2S and water in the production stream:

1.Hydrogen sulphide stress cracking: this type of corrosion causes cracks in the material which eventually fails under load or internal stress; failure may occur at any time during the working life of the material, in some cases immediately after it is put into service.

2.Embrittlement: the hydrogen derived from the hydrogen sulphide by chemical reaction embrittles the material, causing failure to take place within a short time, even in a matter of hours.

3.Uniform corrosion: the surface of the metal is attacked in a fairly uniform manner, with occasional pitting.

The destruction by hydrogen occurs when the partial pressure of H2S in the gas is higher than 0.0142psi. H2S stress corrosion occurs in steels having a hardness higher than Rc22 (237 Brinell). In cases where high residual stresses are present it is possible for H2S stress corrosion to occur at harnesses less than Rc22. Rough handling of equipment may cause dents and scratches which could have a local hardness exceeding Rc22, even if the base material is under Rc22. These dents have often been the cause of failures and consequently careful handling of tubing of tubing tongs is of vital importance.

For combating sour corrosion the use of an inhibitor may lead to risk since the smallest flaw may lead directly to a crack/destruction. Selection of suitable materials, although possibly costly, is the best defence against this type of corrosion. Acceptable materials for H2S service are specified in NACE Standard MR-01-75 (1978 revision). "Sulphide Stress" Cracking Resistant Metallic Material for Oil Field Equipment" (National Association of CorrosionEngineers). A broad outline of these material is given in the following sections.

6.3.1 Acceptable

1.API grade J55, K55, L80 and C75 material (preferably type 2) with a max. hardness of Rc22.

2.Low-alloy steels with a max. hardness of Rc22.

3.300 series stainless steels, in annealed condition. Max. hardness Rc 22.

4.K-Monel, hot rolled and age-hardened. Max. hardness Rc35.

5.Inconel and InconelX, max. hardness Rc35.

6.Hard-facing with stellites, colmonoy and tungsten carbide. Base material, max. hardness Rc22.

7.9% Cr -1% Mo steels quenched and tempered with a max. hardness Rc22.

8.Carpenter A-286 steel with a max. hardness Rc35.

9.Hastelloy B and Hastelloy C.

6.3.2 Not acceptable

1.Steels with a nickel content of more than 1%

2.Series 400 stainless steels

3.Precipitation hardened steels

4.Cold worked steels (below 1000°F)

5.Copper, copper alloys

6.Free machining steels (containing sulphur and lead)

7.High-strength steels

6.4 Low temperature service

For selection of materials and fabrication requirements not only corrosion but also the design temperature of production test equipment, including piping and accessories must be taken into account. In particular during a production test of a gas well the operating temperature can drop due to gas expansion. For temperature conditions as low as -20°F, sour service surface equipment is readily available from production test contractors and suitable for most exploration well testing conditions. However, if "low temperature source service" equipment is considered necessary below -20°F, then equipment should be specified to be suitable for low temperature -25°F (or lower). This design temperature was set at -25°F as at this design temperature impact testing is mandatory in accordance with the ASME code VIII division 1. Also stress relieving is mandatory at design temperatures below -20°F.

Materials, piping and accessories for low temperature sour service have to be suitable for operation at the minimum temperature and at the maximum allowable working pressures. As this low temperature sour service equipment is rented from service companies the Group company supervisor must ensure that adequate proof is handed to him by the service company concerning the acceptability of the test equipment.

6.4.1 Materials and fabrication standards for low temperature sour service

The following materials and fabrication standards have been set in order to safeguard well testing operations:

1.Vessels and piping shall be manufactured in accordance with ASME code VIII division 1.

2.All vessels and piping welds shall be 100% X-rayed.

3.All welds to be made under pre-heat condition of 212 degrees Fahrenheit with low hydrogen electrodes; permanent backing rings shall not be used.

4.All welds are to be stress relieved, maximum hardness Rc22 after stress relieving. Inspector selected welds are to be checked with a portable Vickers or Rockwell tester. (Stress relieving has been introduced in these requirements to ensure that fully ductile welds and heat affected zones will be present). Unfavourable material conditions could be present in view of high carbon contents of many American standard materials. Pre-heating, low hydrogen electrodes and stress relieving are introduced to prevent specifying low carbon content materials, which are generally not available in the USA.

5.Separators, including connections and piping, should be designed for low temperature service. The design temperature to be -25°F, unless otherwise specified at a lower temperature.

6.For low temperature sour service all accessories (valves, etc.) shall comply with appropriate NACE specifications. (Certain refinements taken up in the Company Sour service specifications are valuable, however, in order to simplify NACE specifications are accepted together with stress relieving and design temperature of -25°F).

7.Inspection reports from independent inspectors should be made available to the operating company renting the production test equipment. The Group operating company should also be provided with relevant data sheets, material specifications and certification of chemical composition and physical properties including hardness and Charpy impact values. Group company supervisors should scrutinise this data and make sure that the following pertinent information concerning rented test equipment is available, prior to production testing:

a)Evidence that materials used in fabrication of low temperature production test equipment, where applicable, are suitable for -25°F.

b)Proof that welding has been 100% X-rayed and is accepted by an independent inspector.

c)Proof on stress relieving of welds and hardness check by an independent inspector.

Production test equipment is to be rejected if (1), (2) and (3) do not conform with requirements.

Should standard surface equipment/materials downstream of the X-mas tree master valve be in use by a group company, and early detection indicates the presence of H2S, production testing is not to continue and the well must be killed.

Complete specifications for sour service test equipment, suitable for low temperature service is given in Section 12 of this report.

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