Meeting the challenges of a deepwater wildcat off northern Brazil

During drilling operations, permeable intervals reduced the pore/fracture pressure window, which led to severe well bore ballooning (loss of drilling mud with pumps on and gaining lost mud with pumps off) due to additional bottom hole pressure caused by the equivalent circulating density (ECD). As in most deepwater operations, the tight pore/fracture pressure window must be managed to ensure each casing string is set as deep as possible to reach the target TD with the available casing strings. For the Algodoal well, this was accomplished by using several tools to ensure each casing setting depth was managed to reach optimum depth. The risks of losing the well versus not reaching the objective were weighed and managed to ensure no harm to personnel or the environment. Drilling in these conditions was enabled only through the use of some of the best available equipment, software, and experienced people.

Tools

Several tools proved to be advantageous in differentiating between a formation kick and ballooning.

• On the trip out of the hole at section TD, slow passes were made over suspected loss zones to capture and compare a “repeat pass” LWD resistivity log with the original. The comparison of the two logs clearly delineated drilling mud invasion and helped to confirm where ballooning events were occurring. This historical experience was used in the next hole section to assist with identification of ballooning in similar strata

• Mud logging data capture and analysis software allowed not only connection fingerprinting, laying data from multiple connection flow-backs over top one another, but also over top data from other wells. A detailed accounting of fluid lost and recovered, properly adjusted for product additions, cuttings, pipe displacement, and other factors could also be maintained over short-term events and the entire hole section

• Down-hole pressure while drilling (PWD) enabled finer control over equivalent circulating density effects and aided in post analysis of ballooning events. PWD could also show when ballooning flow-back mud was of sufficiently low density that it should not be brought into the riser due to potential gas entrainment and instead circulated through the choke

• Continuous measurement of return mud density, oil/water ratio, gas, and chlorides fed into the mud-logging database and analysis software was reviewed with the other data above to determine the most likely situation for all down-hole loss and flow events

• Return flow intensity and controlled flow back to the trip tank were used together while fingerprinting connections due to the high sensitivity required for early detection of flow in an environment where compressibility and ballooning effects dominate flow and minor deviations in flow-back must be differentiated.

People

While this well was unique to this area of the world, despite pushing the limits of worldwide experience, it was analogous to wells drilled in other areas of the globe. Drawing on a well-site and office-based team with experience in deepwater and exploration drilling from multiple basins was a key to well delivery. On the rig site alone, 28 nationalities were represented. Personnel involved in well monitoring and control collectively represented experience from most if not all deepwater basins around the world. Rig site and office staffs of the operator, drilling contractor, mud service company, and mud-logging company were all involved as operational decisions were made. Under the guidance and authority of a single leader with accountability for the entire project, decisions were made by consensus despite objectives not always in alignment between parties.

Diverse experience was especially important during ballooning conditions. At section TD in the deepest sections, the well was repeatedly flowed, fully circulated, and flowed again to achieve stability to trip the drill string. The influx was lost mud in all cases. To ensure that a gas kick was not circulated into the riser above the subsea BOPs, flow-back and bottom hole pressure data were overlain with connection flow-back data and data from other wells where ballooning had been experienced.

The well-site leader, engineer, and pore pressure specialist on the rig made consensus decisions to stop or continue to flow mud back into the well during ballooning flow-back events. While experience on similar projects between team members might have lead to speedier decision-making, the challenge and alternate perspectives within the group of very diverse backgrounds made for much more solid decision-making. Well-site leader experience with formation ballooning was essential to reaching TD, as procedures followed would be considered unconventional or unacceptable in most other situations.

Communication tools

An extensive offsite team, including worldwide technology experts, involved in the decision-making requires effective communications between the remote rig-site and multiple sites onshore in multiple countries. A typical meeting to review the pore pressure situation or undertake a continue or stop drilling decision involved parties in Belem, Rio de Janeiro, Houston, and multiple other locations to ensure the input of key experts or decision makers was always available while their time was demanded in other locations or on other projects.

Satellite Internet allowed for the use of Internet protocol meetings and conference calls for multiple parties to be able to interact utilizing presented material and analysis software. Adequate bandwidth to the rig and all onshore sites was critical to this well reaching its objective.

With Algodoal being such a technically challenging project, accessing the latest and most appropriate technology had a direct effect on delivering the well objectives. The most important technology transfers that occurred within BP were the use of the “Big Bore” wellhead system, real time pore pressure monitoring and prediction, a linear alpha olefin (LAO) synthetic oil based mud (SOBM) system to facilitate head space gas analysis, a fifth generation drillship for remote logistics and current management versatility, and overall operational experience.

Service providers were selected based on their ability to provide and support the appropriate technology in Brazil. People played a critical role in the transfer of this technology and in several instances the awarding of a contract or service was contingent on association of specific personnel with key skills and knowledge. This effort proved worthwhile as fewer issues were encountered with service lines in which BP approved key personnel.

Logistics management

One of the biggest challenges in any remote operating arena is equipment and personnel logistics. The Algodoal project was planned in Houston, with the assistance of BP Brazil’s local staff and management in Rio de Janeiro. A supply base was set-up in Belem, Brazil, to handle logistics and Macae, Brazil, was used to supply some third party equipment and supplies.

Logistic challenges ranged from six day one-way truck runs from Macae to Belem, 3,000 mile rig and supply vessel mobilization from Fourchon, Louisiana, to Brazil, three-day one-way crew changes in and out of Brazil, 200-mi one-way helicopter runs, and 36-hour one-way supply vessels runs from Belem to the rig location on the Algodoal well. Early in the planning process, logistics was recognized as one of the biggest challenges to ensure safe, timely, and efficient delivery of equipment and personnel to the project. To this end, BP Brazil contracted a first-class complement of logistics support equipment:

• Fifth generation drillship with large variable load capacity for mobilizing equipment from the United States
• Three large Gulf of Mexico supply vessels to mobilize equipment, liquid mud, and other tangible equipment
• Two GoM fast supply vessels for back-up crew change capability, “hotshot” supply, and for use during flight following operations for the long helicopter runs
• Two Super Puma helicopters for crew change and search and rescue. Dedicated satellite tracking for flight following of each helicopter was also employed to ensure fast response in the event of an emergency
• Full medical facilities at Belem, Brazil and on the drillship in the event of an emergency (never required)
• First class supply base at Belem, including: bulk facility, trash recycling facility, cranes, forklifts, pipe yard, and training facility
• In-country real time tracking of truck deliveries from Macae to Belem.

Preplanning

While Brazil has an established oil industry and oil service company community, the majority of wells drilled in deepwater are not deep wells and do not require nine casing strings. This, along with the lack of use of SOBM in exploration areas, did not allow tangible equipment supply for the operation from Brazil. The Big Bore subsea wellhead system and casing for the operation were purchased in and imported from the USA as was the SOBM, unique cement blends, hole openers, drill bits, stabilizers, casing running tools, liner hangers, and other tools required for drilling and casing a Big Bore type subsea well. This required rigorous planning to ensure no equipment was left behind.

There was no backup or spare equipment available in Brazil for the planned well program, and import of emergency parts required two to three weeks for customs clearance. Significant preplanning was required to be able to import a drilling rig, workboats, helicopters, and all the equipment required for the operations. This required knowledgeable in-country personnel and external shipping agents. Preplanning allowed all of the equipment to be cleared on arrival, offshore Brazil without having to bring the rig into a port facility. This was only possible through working closely with customs inspectors in Belem, Macae, and Rio de Janeiro.

Local BP staff played a key role in this success by establishing working relations with key personnel in advance of the mobilization. This ensured the specialized equipment could be cleared offshore and the specialized vessels and helicopters could be imported for “just in time” start-up of logistics which coincided with the arrival of the drilling rig. With the proper focus and planning, weeks of costly delays were avoided.

Personnel safety

BP core values and minimum criteria for operating the project mandated that all personnel and communities involved in the operation come prepared to work safely and protect the environment. To ensure personnel safety in the remote area, offshore northern Brazil, detailed contingency plans were prepared to cover medical emergencies on the drilling rig, vessels, helicopters and community emergencies. During the operations, satellite, shore base, drilling rig, and supply vessels monitored helicopter flights. Due to the 200 mile one-way trip time to the rig, a fast rescue vessel was stationed mid-way between land and the drilling rig to ensure fast rescue in the event of a helicopter ditching. The two Super Puma helicopters were imported because there were no suitable alternatives available in Brazil. A dedicated BP aviation QA/QC engineer supervised the start-up and operations of the aviation piece of the operation.

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Protecting the environment

To ensure the operation was run in an environmentally responsible manner, BP Brazil’s HSSE department worked closely with the Brazil environmental ministry and received the first permit to use SOBM in offshore exploration operation in Brazil. Waste recycling was another first for offshore operations in northern Brazil. All trash and waste generated by the operations was recycled at the shore base in Belem. In addition, BP employed a full complement of oil spill contingency clean-up equipment and held full deployment drills to ensure that any spills of drilling fluid, fuel, or other hydrocarbon materials could be quickly contained in the river system and ocean.

During the five months of operation in Brazil, there were no personnel or equipment lost time incidents and no environmental incidents. Once again, proper preplanning with key in-country personnel and contractors proved that a remote, new start-up operation can be successfully completed without harm to people or the environment.

Technical and operational resources

A key component to delivering the Algodoal well was effectively drawing on BP internal experience and expertise in well planning and operational decision-making. This support was critical to understanding and mitigating against the potential severe metocean conditions. Internal BP exploration and production technology (EPT) experts were engaged on critical well components such as wellbore structural design, analyzing metocean data, drilling riser design, vortex induced vibration (VIV) and rotary table clash analysis.

Operational peers were also included in the planning process in order to access BP’s global experience and best practice network. One valuable condition was the Brazil team being co-located with BP’s GoM deepwater exploration and production group in order to most effectively incorporate their experience into the project.

Another critical area for well planning and operational decision-making was the utilization of third- party technical resources for analytical input on wellbore structural design, VIV, clash, and riser analysis. A third party for real time current data collection, management, and analysis deployed an acoustic Doppler current profiler (ADCP).

The internal and external technical and operational resources were managed together in order to effectively deliver the Algodoal well. BP’s project management processes (PMPs) were used to systematically plan the well and ensure that the appropriate milestones and work plans were delivered effectively. One example of this process working well was in holding a current management peer assist meeting with the internal and external experts to aid in analyzing and mitigating the metocean risks associated with this project.

Metocean challenge

The metocean environment at location presented a challenge being dominated by the North Brazil Current (NBC), which sets towards the west or northwest at the surface all year round with a maximum strength measured up to 5.0 knots. The surface NBC tends to have a river-like meander pattern with oscillations on and off the slope area over periods of several weeks with variability between 1.0 knots and 5.0 knots. This high surface current environment posed a tangible threat to continuous drilling operations with exposure to significant cost and operational risk.

The risk to the project was roughly quantified from the available dataset that 20% of the time the current was greater than 3.0 knots, which was the operational drilling limit determined by Global Santa Fe (GSF) riser analysis for a yellow watch circle alert. Once this 3.0 knot limit was reached the drill string would have to be hung off in the BOP’s in preparation for an emergency disconnect.

With a well time estimate of 100 days this could signify 20 days standby over the project duration waiting on current in a remote exploration location with a significant spread rate cost. The problem was real and most likely to occur, and thus required a defined operational plan to mitigate exposure. The planning phase focused on the GSF riser analysis and structural design to determine the operational constraints, along with the conductor and wellhead requirements. The relatively shallow water depth in a drift off scenario would expose the wellhead and conductor to a high bending moment load with risk of fatigue and failure.

The technical planning phase advanced to developing an operational plan. A riser and current management peer assist was an integral part of the process to draw on internal and external expertise. One of the key outcomes of the peer assist was reinforcement that the time and associated cost to install riser fairings of 24 hours incremental on riser running was warranted to mitigate against downtime waiting on high current. Riser fairings have a positive effect on reducing riser flex joint angles and minimizing VIV.

BP’s Floating Systems Group was an integral partner in the overall process to interpret and advise on the metocean dataset, QA/QC third party technical analysis, and develop and implement operational plans. A critical component in the operational planning was third party analysis to determine what current environment would require open water casing strings (36-in., 28-in., 22-in.) and riser to be drift run to control clash (rotary table, diverter housing, moonpool) and VIV issues.

Many factors entered into the drift running analysis and decision-making process such as current profile, water depth of casing/riser string, relative vessel drift to current speed, and block height. Prior to running each casing or riser, the decision process was followed which resulted in all open water casing strings and riser being drift run on Algodoal. There were no VIV or ‘clash’ failures on Algodoal.

References

1. Aston, M.S., Alberta, M.R. et al: “Drilling Fluids for Wellbore Strengthening,” paper SPE/IADC 87130 presented at the IADC/SPE Drilling Conference, Dallas, Texas, Mar. 2-4

2. Alberty, M.W., McLean, M.R.: “A Physical Model for Stress Cages,” paper SPE 90493 presented at the SPE Annual Technical Conference and Exhibition, Houston, Texas, Sept. 26-29

Editor’s Note: This a summary of the OTC 17970 presented at the 2006 Offshore Technical Conference in Houston, Texas. May 1-4, 2006