Plugs help overcome cementing issues

Drilling and cementing naturally fractured carbonate reservoirs can be challenging and cause serious well-control issues because of the high probability of heavy or total losses. The Kashagan field in the Caspian Sea area is characterized by a carbonate reservoir with high pressure, high HS and COcontent, and the presence of natural karsts/fractures.

Because of well-control issues resulting from heavy losses while entering the reservoir section, the closed-hole circulation drilling (CHCD) technique is often used to mitigate the problem. To overcome poor liner cementing issues with consequent reduced production performances of some wells, an alternative completion architecture with a 4 1/2 -in. slotted liner and a preinstalled plug to act as a second barrier while running the liner was evaluated. Among all options, a chemical cement plug, set inside a 4 1/2 -in. blank joint, was deemed to be fit-for-purpose for ease of installation and removal procedures. After successful laboratory and yard tests, three plugs were installed in the field.

FIGURE 1. The original cement sample (left) is compared to the sample after 30 days of exposure in an HS and COenvironment (right). (Images courtesy of Eni)

Selecting best completion assembly

The first experiences of wells drilled in the Kashagan rim area have proved to be very challenging in managing the drilling losses and in obtaining good cement isolation in the reservoir section. The 5 1/2 -in. liner set inside the reservoir was cemented and then perforated in overbalanced conditions after the upper completion had been deployed. In some cases, the liner cement job was very poor; therefore, optimization of the perforated sections was hard to reach because of fluid communication behind the liner.

To improve the productivity of these wells, an alternative design was evaluated. The alternative scenario was to drill the 8 1/2 -in. section in the cap rock down to the top of the reservoir before encountering the karst zones and then set and properly cement a 7-in. liner. Then drilling operations were resumed with a 5 7/8 -in. bit in CHCD conditions through the reservoir down to total depth. The open hole was then cased with a 4 1/2 -in. slotted liner.

The feasibility of running the upper completion in a well with a slotted liner was evaluated and considered unsafe. The main issue was how to isolate the karst formation while running the upper completion assembly and during the following fluid displacement operations.

To comply with the CHCD running procedures and improve the overall scenario of safety, the slotted liner and the packer assembly was to be run with a preinstalled plug set in the blank section below the liner hanger and properly tested. Various types of barriers were discussed and assessed. The plug needed to be able to withstand the maximum anticipated load of 6,500 psi differential pressure generated from below during the displacement of the completion fluid with the packer fluid (i.e., base oil).

The plug installation, testing, and retrieving procedures as well as the possibility to reuse the plug were also considered. Among the various options explored, the final preference fell on a chemical (soluble-cement) solution because of its installation simplicity and ability to be more easily removed than the others.

Acid-soluble cement

The cement system used to prepare the preinstalled plug was a magnesium-based Sorel cement, which is normally used to prevent fluid losses in productive formations where the permeability could be restored with an acid job.

It is characterized by low permeability, high compressive strength, thermal expansion properties, no performance loss when in contact with drilling mud or completion fluids, acid solubility, and drill-out ease. In this case study, the acid-soluble cement (ASC) system was used to create a removable barrier installed within the lower completion assembly. It has been used as a cement plug created by filling a pup joint with the ASC system.

Laboratory tests

Laboratory tests were performed to evaluate the suitability and the compatibility of the product with the downhole and operational condition of the Kashagan field.

The slurry was mixed and cured under controlled pressure and temperature conditions, which were shown to have a great impact on the performance of the set slurry.

The main lab tests that were carried out were mechanical shear-bond strength, water permeability, acid solubility, compressive strength, expansion properties, hydraulic-sealing properties (bench scale), and hydraulic-sealing properties (large scale).

The ASC presented sufficient shear-bond strength, providing a mechanical load of 24 kg/sq cm/sq cm corresponding to a hydraulic pressure of 809 kg/sq cm (11,550 psi) per meter of pipe. The lab tests confirmed the suitability of the product and defined the best slurry composition.

Yard tests

A yard test was performed to verify the suitability of the plug, simulating the real downhole conditions foreseen in the field. Three grooved joints, each about 1 m (3 ft) in length, were filled with the same batch of ASC and cured for five days under the same temperature conditions at 203°F (95°C) and pressure at 10,152 psi.

The ASC plugs were submitted to the differential pressure-acceptance test at the base according to a dedicated qualification procedure. In this layout, several pressure-up/bleeding-off cycles (up to 8,000 psi) were applied through the test plug. The acceptance criterion was a pressure reduction within 1% of the applied stabilized-pressure value every 15 min. The results of the yard tests were successful, and the qualified pup joints were delivered to Kazakhstan for the field application.

Field applications

The ASC plugs were used in three wells drilled in the highly karstified area of the Kashagan reservoir to isolate the formation from the upper part of the well during the deployment of the completion string.

A schematic of the lower completion section is shown in Figure 2. The lower completion section is openhole with a 4 1/2 -in. slotted liner. The 4 1/2 -in. cement plug joint was installed above the slotted-liner section and just below the hanger system. Once the slotted liner was set and properly pressure- tested, the upper completion string was run in weighted fluid of 1.93 kg/L. Before the production packer was set, the completion fluid was displaced with base oil of 0.82 kg/L. The ASC plug was removed before well cleanup through milling operations and acid spot by means of coiled tubing. The milling operation was performed within 30 minutes without problems.

FIGURE 2. This well schematic shows the plug position.

Acknowledgments

The authors would like to thank Eni’s E&P PERF Department management for their support and permission to publish this paper.