Collaborative contingency on the Alaskan frontier

Rich in hydrocarbons, with a long history of production, Alaska still holds many unexplored, untapped frontiers that present unique and complex challenges. However, as prospects for easy oil fade and output from existing wells declines, operators are shifting their focus to these previously inaccessible environments that are typically remote, and characterized by harsh conditions and highly pressurized formations. Success in these fields demands extensive preparation, including specialized equipment design and procurement and contingency planning for well completion interventions. Increasingly, early collaboration between operator and service company is also proving to be a critical factor in ensuring well performance and project efficiency in this high-stakes arena.

Fig. 1. Flow chart detailing contingency plan, if the FIV does not open by pressure cycling. Chart: Schlumberger.

To complete multiple, high-pressure wells in a remote field in Alaska, an operator implemented a collaborative strategy to design and develop the first planned CT intervention contingency in the region, requiring 15,000-psi-rated well control equipment. Schlumberger implemented an integrated project management approach, involving more than a year of planning and culminating in the development of multiple technical elements. These included a specially designed CT string, fluid system, and downhole tools, to deliver a fit-for-purpose solution. The undertaking yielded important lessons for future high-pressure CT operations and demonstrated the value of early collaboration with a single service provider, versus the conventional approach of contracting with individual suppliers for each phase of a project, Fig. 1.  

The operator had drilled, but not completed, two wells in the remote Arctic region in 2010 and had agreed to an initial development plan in 2012. The final plan involved completion of the two initial wells, drilling an injection well, and drilling and completing a third production well, with output starting at the end of the 2015-2016 winter. The anticipated bottomhole pressure of the wells was 10,200 psi.

The three production wells were to be completed with formation isolation valves (FIVs), featuring a 5.5-in. outside diameter (OD) and 2.812-in. inner diameter (ID), opened using pressure cycles. The operator selected a bi-directional barrier valve that isolates reservoir fluids in the lower completion, and enhances well productivity by preventing formation damage and minimizing fluid loss. Designed to withstand severe debris environments, the valve also increases safety by providing a downhole barrier against pressure reversals. The completion plan also included setting and testing a packer, and executing a frac-pack treatment.

To avoid downtime, the operator required that a CT unit be on location as a contingency, in the event that the FIVs could not be opened by pressure cycling. If necessary, CT would be deployed into the well, to first clean debris using a junk basket. If the FIV remained closed, the CT team would try to open the FIV using a mechanical shifting tool. Finally, if the shifting was unsuccessful, CT would mill the FIV with a motor-and-mill bottomhole assembly (BHA), to enable continued well completion operations.

OUTSOURCING EQUIPMENT FOR HARSH CONDITIONS

The CT intervention contingency involved several challenges, the most significant being lack of previous experience in an Alaskan well,  where the maximum allowable surface pressure (MASP) was 8,564 psi. Most CT operations in Alaska are performed on wells with a MASP of less than 5,000 psi, with few jobs requiring well control equipment rated for even 10,000 psi.

In this case, because the wells’ MASP exceeded 8,500 psi, the operation required downhole tools and well control equipment, including blowout preventers (BOPs) and dual strippers, rated for 15,000 psi. The team also needed to mill the FIV in large, 7 5/8-in. casing, in harsh conditions that included 30-ppm H₂S (sour gas) and 4.55% CO₂ with ambient temperatures approaching –50° F.

To accommodate these conditions, the operator and service company put the integrated project management model in place during March 2014, to begin preparations for the CT contingency well, in advance of the planned execution. The scope of work involved a technical job design, bringing in third-party providers when necessary. A project readiness assessment tool was used to generate action items required to monitor preparation and reduce the chance of unplanned events in four key areas:

• Risk exposure 
• Complexity and processes 
• People and competency 
• Technology and equipment.

Among the action items identified in the assessment were the need for a complete review of the job design, equipment and job requirements to be performed by technical experts, and strict adherence to a specific guideline for CT operations performed in wells where MASP exceeds 8,500 psi.

SPECIALLY DESIGNED FLUID SYSTEM, CT STRING

Another challenge involved designing a fluid system that would control the high pressure in the wells but that could also be pumped through the CT string at circulating pressures that would not exceed the limits of the pipe. Engineers needed to calculate the annular velocity, determined by the dimensions of the completion and the pump rate through the CT, which could be achieved while milling the FIV.

Fig. 2. Schematic for well A. Image: Schlumberger.

Well A, the new production well, would serve as the basis for the fluid system design. It had the largest completion size with 7-in. tubing and an ID of 6.004 in., and a 7 5/8-in. liner with an ID of 6.375 in. The minimum restriction for the CT intervention was 2.812 in., the ID of the FIV. This limited, to 2 1/8 in., the maximum OD of the downhole motor that would be used to mill the valve. The maximum rate to pump the fluid system through the 2 1/8-in. downhole motor was 1.1 bbl/min., Fig. 2.

Based on these dimensions and the pump rate, the calculated annular velocity of 28 ft/min. required the design of a gelled fluid system for well clean-out. To mill the FIV, M-I SWACO, a Schlumberger company, proposed a 10.6-ppg viscosified sodium bromide fluid system, using the Flo-Vis* Plus viscosifier, which provides superior hole-cleaning and suspension, improved hydraulics, and reduced torque and drag while minimizing filtrate invasion. The fluid would provide hydrostatic pressure to manage the wells’ high pressures and provide viscosity to carry particles to the surface, at a circulating pressure below the burst pressure of the CT string.

For wells with MASPs of 8,564 psi, the CT string needed to be engineered to ensure that the operational requirements would not exceed the maximum tension, compression and pressure limits of the string. The minimum wellbore restriction of 2.812 in. required use of a 2-in. CT string, designed and milled specifically for this project, to fulfill the job objectives in all four wells. The contingency was planned, so that the CT would not be run deeper than the sump packers, resulting in a maximum CT depth of 17,020 ft.

Like the fluid system, the CT string was engineered to meet the specifications of Well A, which had a maximum CT depth of 16,820 ft. The string also needed to be able to mill the FIV at 16,332 ft, and perform a clean-out to a maximum depth of 16,820 ft in Well A. To account for the H₂S conditions, a CT material grade with yield strength no higher than 90,000 psi was chosen. Higher yield strengths, and resulting higher collapse resistance while performing CT interventions in those conditions, can lead to string failure, Table 1.

To further mitigate risks, a backup fluid pump was selected to prevent loss of CT circulating pressure. Additionally, the CoilScan* engineered pipe management service would continuously monitor the pipe in real time, to ensure pipe integrity. The pipe inspection system monitors various parameters, including wall thickness, OD and length of the pipe in real time. It tracks such defects as corrosion, pitting and other forms of mechanical damage. Hydrogen-induced cracking resistance also was measured for five samples of the CT pipe, Fig. 3.

SELECTION OF CT BHA COMPONENTS

Planning for the FIV milling contingency involved careful selection of CT BHA components, including downhole check valves and connections, to ensure they had a working pressure of at least 15,000 psi. Because no 15,000-psi-rated CT connectors were available on the market, a risk reduction plan with preventative and mitigating measures was put in place, to enable use of a 10,000 psi-rated connection in this operation.

Fig. 3. The CoilScan service minimizes NPT by monitoring wall thickness and diameter, depth, and defects in real time. (Courtesy of Schlumberger)

The risk reduction plan dictated that a full column of 10.6-ppg viscosified sodium bromide fluid be maintained in the well at all times, and that the well be kept continuously overbalanced by maintaining adequate choke backpressure. Additionally, there would be no well flowback while CT was in the well. Any influxes would be circulated out with appropriate choke backpressure, and returns would be monitored to ensure that the barrels of fluid pumped in the well were equal to the barrels exiting the well. The CT connectors would be pressure-tested to 10,000 psi. Should wellhead pressure reach the maximum well control pressure, the CT would be cut at surface with BOP shear rams, and the well shut in.

Selection of the mill was based on previous, extensive testing and general practices for milling with CT. The milling BHA consisted of a 2-in. OD internal breech lock CT connector; a 2 1/8-in. OD dual-flapper check valve; a 2 1/8-in. OD jar; a 2 1/8-in. OD rugged hydraulic disconnect; a 2 1/8-in. dual-acting circulation sub; 2 3/8-in. OD downhole magnets; a 2.65-in. fluted centralizer; a 2 1/8-in. OD positive displacement motor; and a 2.65-in. OD four-bladed concave mill, with cutting button inserts backed up by crushed carbide. The mill had a radius of concavity larger than the FIV ball ID, to prevent large debris from being cut out of the top half of the ball and interfering with the milling on the bottom portion of the ball.

After BHA selection, the operator asked for a test to verify performance and optimize the mill design. The CT unit was mobilized to the wellsite in August 2015 and remained on standby until March 2016.

VALUABLE LESSONS GOING FORWARD

The operator accomplished the project objectives without a CT intervention. However, the project demonstrated the value of collaboration in planning and designing an operationally efficient CT intervention in a remote Arctic environment, where MASP exceeding 8,500 psi requires 15,000-psi-rated well control equipment. The operation also provided important lessons going forward.

For example, the use of newer high-strength CT with improved fatigue performance and H₂S and sulfide stress cracking (SSC) resistance would increase the life of the string and enable the use of material with a yield strength higher than 90,000 psi. This could significantly improve performance in H₂S environments under static load conditions. Tests suggest that the improved performance of new CT grades also could allow the use of 20,000-to-30,000-psi higher-yield strength in SSC environments.

It also was determined that a 15,000-psi quick-latch connection to enable a secure connection between the CT BOP and stripper would enhance safety and efficiency in future CT operations requiring 15,000-psi rated equipment in the well control stack. The quick-latch connection minimizes the need for field operator assistance while rigging up the pressure control stack. It is a safer alternative to manually bolting the last flange of the well control stack, saving rig-up-and-down time.

Finally, because fluid systems containing zinc bromide brines to increase fluid density can adversely impact BOP elastomers, this contingency was planned, so that the wells would not contain the 16-ppg zinc bromide completion fluid when CT was in the well. A fluoroelastomer that is compatible with the fluid system should be used in these interventions, and inspected and replaced more frequently than for conventional CT operations, due to the low ambient temperatures reaching nearly –50° F. 

*Mark of Schlumberger

ACKNOWLEDGEMENT

This article was adapted from SPE paper 184768-MS, which was presented at the SPE/ICoTA Coiled Tubing & Well Intervention Conference & Exhibition, held in Houston, Texas, March 21–22, 2017.