Pre-planning well abandonment protects reserves, fluid movement

Technology has played an ever-increasing role in well drilling and production operations, but has had little impact on abandonment planning. The mechanical abandonment of the well is somewhat of an afterthought to many operators.

Jan 1st, 1998

Long-term reliability enhanced through multi-step process

Charles Kelm, T.Slocum
Halliburton Energy Services
Technology has played an ever-increasing role in well drilling and production operations, but has had little impact on abandonment planning. The mechanical abandonment of the well is somewhat of an afterthought to many operators.

Cost and regulatory requirements have been the main drivers for most operators when making decisions on how a well should be abandoned and who should do the work. Slowly, as the concern for the environment has taken on more prominence and as more regulatory agencies have assigned all future liability to the operator, improvements in development and abandonment techniques that reduce long-term risk have generated more interest.

The aim of each well abandonment should be to protect the remaining reserves in the reservoir and control fluid movement within the wellbore to minimize the risk of contamination of fresh water sources and to prevent surface or sea pollution. To fulfill all these objectives can, however, conflict with the operator's need to control cost. It is often easier to meet the regulatory requirements than to physically ensure the long-term protection of the environment and the remaining reserves.

For instance, there is an increasing trend in the industry to use rigless abandonment techniques. Cranes have replaced rig derricks and torches have replaced tubing and casing tongs, the idea being to speed up abandonment operations and thereby limit the final cost. Rigless techniques may meet regulatory needs, but because of flexibility limitations they can also increase the long-term risk to the environment and the operator.

Fluid flow control

Formation fluids move from higher-pressure to lower-pressure intervals where a flow path exists. A properly executed well abandonment will limit fluid movement until nature restores the static balance that existed before the well was drilled. Fluid flow within a wellbore is controlled by three mechanisms:

  • The casing and cementing programs that were used to construct the well
  • Abandonment operations combining mechanical plugs and cement designed to complement the original drilling program
  • The natural barriers in the well created by the fluids and formations physical properties.
Of these mechanisms, man has control only of the first two. It is very important that they complement each other to ensure that the wellbore remains stable until nature restores the presssure balance.

Best practices

The best abandonment practices described below are appropriate only when combined with successful primary cement jobs. Some of the points may seem obvious, but I've seen numerous operators fail to implement them over the past two years.

Firstly, all cement plugs should be designed for the static temperature at the setting depth and tested at the circulating temperature to ensure adequate placement time. As the cement plugs are expected to remain in place for all time or until the natural barriers are restores, the cement composition should be designed to the highest standards for long-term isolation. All cement plugs must be set in a clean, gas-free environment to minimize the risk of contamination. Most important of all, cement should not be bullheaded down an annulus during abandonment since control of the placement depth is lost and the probability of channeling and poor bonding are greatly increased.

It is critical to isolate all perforated intervals. Since the intervals routinely contain hydrocarbons and the interval's pressure has normally been changed due to production or injection, this is a major source of future pollution. To ensure that the interval is sealed off, the plugging operation should extend into the formation itself. Using either an ultrafine cement or a polymer to penetrate the formation and any near wellbore channels followed by a normal-grind cement slurry will greatly reduce the possibility that the production interval will be the source of any future pollution. Penetration of the formation matrix is especially important in gravel-pack completions where a normal-grind cement will not penetrate the gravel-pack sand.

It is very important that the over-pressured interval be isolated from the surface during abandonment operations. Drilling reports for the well should include the depth where over-pressure begins. A cement plug should be placed in the production casing across or immediately above the over-pressured interval. All liners not tied back to the surface should also have cement placed across their top.

Each uncemented annulus open to the mud line must be isolated as deep as possible. The cement should be circulated in place once the annulus is clean. However, since most casing annuli contain some type of mud that was left in place during drilling operations, cleaning the annulus before cementing can be difficult and could require the casing to be pulled.

It is advisable, therefore, to recover the tubing from below the surface casing shoe and then cut the production casing immediately above the shoe. This action provides a large flow area for circulation which should aid cleaning of the annulus and cement placement. Also, it relieves the tension in the casing string before the cement is pumped.

The surface plug is the last plug pumped and is critical to the prevention of surface pollution and fresh water contamination. All uncemented casing strings should be cut and pulled from at least 300 ft below the mud line. A mechanical plug should be set in the smallest string cemented back to the surface, and a balanced plug of cement at least 200 ft long should be circulated on top of the mechanical plug.

Complete removal of the structure and wells requires that all casing strings be cut below the mud line and recovered. If practical, all casing strings remaining after the surface plug is set should be cut using either mechanical/hydraulic cutters, abrasive cutters or shape charges, as these techniques avoid extreme distortion of the pipe wall. The cheaper alternative, bulk explosives, can damage all the casing strings severely, making re-entry, if required, much more difficult and costly.

If wellbore junk is left in the tubulars during the operating life of a completion, this can increase the uncertainty and mechanical risk when the wellbore is abandoned. Even when the junk does not impede the ability to inject into the perforations, it often makes it impossible to add mechanical barriers deep in a well and to confirm the placement depth of cement plugs.

However, if the decision is taken to leave the junk, a preliminary abandonment plan should be developed to confirm that the well can be successfully abandoned later without recovery of the obstruction. Junk left in a well for long periods is often more difficult to recover subsequently.

Generally speaking, the remedial cost of re-entering an improperly abandoned wellbore can be significant if a future well-control problem (gas or oil flow) emerges after the wellbore has been plugged, the equipment demobilized and the structure/facilities decommissioned. The resulting cost could amount to more than that of the original well construction should a severe blowout occur.

In the past, when wells were drilled in shallow water using relatively inexpensive equipment, there was little perceived need to pre-plan the abandonment. Today, with wells being drilled in deepwater at high angles in hostile and expensive environments, often with limited access after drilling to some annuli, there can be a definite advantage to pre-planning production operations and the final abandonment before drilling the well.

Among the techniques that should be considered, centralizers should be used in the upper portions of the wellbore as well as across the openhole sections to ensure minimum eccentricity during cementing. Centralizers also cut the risk of cement channeling and provide a reasonable standoff in the shallow portions of the well where multiple strings of casing will be cut during abandonment operations.

Cement placed in the shallow portions of each casing string should be designed to take into account pressure and temperature fluctuations the well will encounter during its production life. Current cement designs do not address these fluctuations, and as a result, there are many wells with casing pressure. To mitigate this problem in future wells, a special blend of cement, such as foamed or latex cement, could be applied in the shallow portions of the hole. These blends offer greater flexibility than conventional cement and should be less affected by temperature/pressure changes.

Every casing string should be cemented across or immediately above the next largest casing shoe during drilling operations. Mud in the annulus will never be in better condition than when the well is drilled, so this presents a unique opportunity to place an effective cement plug across each casing shoe.

Cement placement choice will depend on the well's mechanical configuration, the reservoir properties of the formations penetrated and the potential for gas contamination. In wells with long, uncemented sections, a differential valve (DV) tool would ensure that a good quality cement is placed at this critical isolation point. A casing packer run below the DV tool and set in the larger casing before the DV tool is opened will reduce the risk that the cement circulated into the annulus through the DV tool will be contaminated by gas.

Another approach would be to cement the casing shoe conventionally and then bullhead cement the casing annulus from the surface. High pressure testing of casing after cement is fully set is suspected of being a major cause of cement damage that allows communication behind pipe. Effects of pressure testing can be mitigated by using high pressure float equipment that allows casing strings to be tested to 80% of yield while the cement is still fluid. The pressure can then be bled off before the cement begins to set.

Whenever possible, cement tops of inner casing strings (intermediate and production) should be left inside casing but below the mudline. This will enable these casing strings to be cut one string at a time using a technique that is least damaging to the pipe.

Finally, mud should be avoided as a packer fluid. When it comes time to abandon a well that has mud as a packer fluid, a rig is normally required to wash over the tubing and clean the wellbore deep enough to place the required isolation plugs. Mud by itself may or may not be an effective barrier and an operator will assume a lot of risk if the mud is not cleared from the wellbore prior to placing the cement plugs.

Reference:

Deep Offshore Technology conference, The Hague, November 1997.

Copyright 1997 Oil & Gas Journal. All Rights Reserved.

More in Equipment Engineering