Cement jobs in the oil and gas industry are getting a bad rap. Cementing work has been identified as the possible culprit in many onshore fracking disputes. The U.S. Bureau of Land Management reports provide evidence of the role bad cement work has played in accidents.
Production optimization begins with a good completion, and a good completion depends on the integrity of the primary cement job. Every year poor cement jobs cause tremendous costs to the oil and gas industry. Poor cement jobs demand additional cementing operations such as squeeze jobs. These operations are time-consuming and rig-demanding, which in turn leads to economic loss. If a poor cement job is left unattended, the result can be catastrophic.
Clearly, there is room for improvement in cementing technologies to withstand the rigors of well operations and any disruptions that might occur. The integrity of the cement job can use all the help it can get. The manner in which the cement is placed inside the annulus assists with the integrity aspect of the cementing operation, and the wellhead can actually help improve efficiency of the cement placement.
A good primary cement job can prevent remedial work. Successful isolation of the hole and formation is extremely important in preventing the migration of gas and fluid and limiting the environmental impact.
Gaining efficiency in horizontal drilling
The achievement of desired technical objectives via horizontal drilling comes at a price: A horizontal well may be anywhere from 25% to 300% more costly to drill and complete for production than a vertical well directed to the same target horizon. But there are advantages: Operators often are able to develop a reservoir with a sufficiently smaller number of horizontal wells since each well can drain a larger rock volume around its bore than a vertical well could.
An added advantage relative to the environmental costs or land use problems that may pertain in some situations is that the aggregate surface footprint of an oil or gas recovery operation can be reduced by use of horizontal wells. The second key benefit is that a horizontal well may produce at rates several times greater than a vertical well due to the increased wellbore surface area within the producing interval.
This approach offers multiple advantages, including better drainage, lower drawdown and a reduced footprint. Its sole purpose is to help operators develop more of the wellbore. The initial linear portion of a horizontal well, unless very short, is typically drilled using the same rotary drilling technique that is used to drill most vertical wells, wherein the entire drillstring is
rotated at the surface.
Setting the packer and optimal placement of fluids and cement represent areas of challenge in horizontal wellbores. Suspension of the hanger represents a major challenge. The parent hanger body has a tendency to spin before latching once the child is landed, causing a less-than-safe condition and potential rod wear. Also, by nature, horizontal wellbores are deviated, causing fluids and cement to migrate to the low side of the hole, resulting in a less-than-optimal distribution downhole.
Choice of wellhead matters
Because cement integrity is one of the most critical steps in well completion, Cameron has studied the need for enhancing cement jobs. Movement of the pipe during cementing is one of the best methods of improving mud displacement and reducing the number of mud channels remaining after cementing. Rotation of casing helps force the mud from the pipe and formation contact areas and ensures a more even distribution of cement. Special rotating heads are required to allow pumping while turning.
The wellhead is a vital pressure-containing component at surface that can make operational processes more efficient and flexible and enhance the integrity of the well. Internal components such as a rotating mandrel hanger will allow the casing to be rotated through the heel of the lateral while installing and cementing.
Such a rotating feature can help operators ensure the production casing runs the full length of the lateral to achieve a proper cement job. Once the casing mandrel is landed in the wellhead, slotted mandrel shoulders permit cement circulation, removing the necessity to wait on cement with casing slips.
Multibowl nested diverter snap-ring wellhead system
One such wellhead is Cameron’s multibowl nested diverter snap-ring (MN-DS) wellhead system. It incorporates a unique rotating mandrel casing hanger designed to improve cement job integrity and wellbore stability for vertical and horizontal gas wells. The hanger enables the operator to rotate the production casing during installation, promoting better displacement efficiencies, effective zonal isolation and less eccentricity in the pipe during cementing jobs.
The ability to rotate the hanger addresses the deviations inherent in horizontal wells. By rotating the hanger, slurries can be more evenly distributed inside the wellbore. On a recent trial with a major South Texas operator, it was deemed that the rotating hanger saved an estimated eight to 10 hours rig time as compared to using a regular slip-style hanger. This time is traditionally spent waiting on cement to reach an acceptable compressive strength before breaking the BOP stack.
A nested design is new methodology for industry wellhead systems. This design, employed in the MN-DS system, reduces the overall height of the wellhead system, making it ideal for use with today’s high-performance horizontal skidded drilling rigs.
Rather than the typical design of the hanger on top of the pack-off, the nested design consists of a hanger that fits within the pack-off, reducing system height. This hanger can be either a production casing hanger or a tubing hanger, providing the option to complete as a one-stage system if intermediate casing is not required.
Because the system uses a spin-on flange design, no special tubing head or tree adapter is required. The system enables the wellhead and all subsequent casing strings to be installed through the diverter riser/BOP without having to nipple down, providing considerable cost and time savings. The wellhead has the ability, depending on the string configuration, to be installed prior to the rig moving to the pad; the only action required is to nipple up the BOP to the wellhead.
The MN-DS system also offers a higher degree of safety resulting from an internally locked system, which eliminates penetrations from lock screws in the housing. The system is particularly applicable in highly deviated horizontal wells because it offers a secure method of protecting the wellbore during drilling operations. Also, the potential for rod wear is diminished because tension is maintained throughout the packer-setting process.
Other examples of equipment helping to ensure well integrity are back-pressure valves and pack-off systems. These can be installed into the rotating mandrel to provide a barrier for both the bore and the annulus to secure the well at surface.
In artificial lift applications, the system’s tubing hanger keeps the tubing string in tension to better endure the sucker rods’ constant up-and-down motion, thereby maximizing the life of the tubing. About 200 MN-DS wellheads have been installed and are operating successfully in the field.
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