Recent predictions indicate that global demand for oil will rise by 2.2% this year, with further increases throughout 2011 due to improving economic conditions. This amounts to the production of 86.6 MMbbl/d of oil for the duration of this year, increasing to 87.9 MMbbl/d next year.

Current economic uncertainty raises questions over whether these targets are achievable. And while the debate regarding deepwater drilling continues, especially in the Gulf of Mexico, the focus on technological advances in well integrity as a solution to meet the increasing demand for hydrocarbons becomes even greater.

The challenge
With this in mind, operators will have to revisit mature assets to extract existing reserves. However, this comes with its own issues, as up to 40% of the world’s oil wells are shut in or operating with dispensation due to problems with well integrity.

With the right technology, leaks in casing, tubing, well valves, and connections are diagnosed relatively easily, but fixing

Platelets are engineered specifically for the size of the leak and the operating conditions of the system. (Images courtesy of Brinker Technology)

them traditionally has been more difficult. In the past, issues that have had to be considered include cost, the availability of rigs and/or a workover unit, personnel, leak fixing processes, the weather, and third-party dependencies, all of which can result in extended long lead times to bring shut-in wells back online.

There also are significant planning and logistics issues to be considered. A rig workover can be a complex and risky process that sometimes can introduce bigger problems.

For example, removing a wellhead for the workover could impact well integrity and bring about HSE risks associated with performing well intervention. Lengthy downtime can be experienced along with lost production. Months often are wasted waiting for a rig to be mobilized and then deployed. This can impact production and revenue targets.

One would expect a wish list of items an operator would require of an integrated system to bring a well back online would include a robust, proven and qualified solution; wellsite identification and diagnosis of a problem; a low environmental footprint; fast delivery; simple deployment at the well site; low risk to well infrastructure and minimal disruption to workflow; and a solution that is not extensively resource-dependant.

A proven solution
In answer to these issues, Brinker Technology has developed a rigless through-wellhead workover solution that is

Telepath identifies the size, shape, location, and context of a leak and identifies the platelets required to fix it.

compact, mobile, easily and quickly deployed, and can bring wells back online in hours. The technology has been field proven across a wide range of applications, including well integrity, wellhead valves, subsea, and infrastructure. Fully certified and qualified as a permanent barrier gas-tight seal at 302ºF (150ºC) and 5,000 psi, it also meets and exceeds QHSE regulations.

The solution incorporates innovative Platelet barrier technology, Telepath leak location system, and Brinker’s Plasma product for dynamic seals. The first step is for Telepath to identify the size, shape, location, and context of a leak, which can be done in less than an hour. This eliminates the need for an expensive and time-consuming caliper run. Telepath results identify the Platelets required to fix the leak without the need for a costly and risky invention.

Originating from observations of how the human body responds to cuts and wounds where platelets in the blood are drawn to the cut and create a seal, its use in the oil and gas industry has been designed around deploying free-floating discrete particles into a flowing system. The platelets are engineered specifically for the size of the leak and the operating conditions of the system. Platelets are pumped downstream while suspended within an inert carrier fluid. When they reach a leak, pressure differential forces entrain them into the defect, where they lock in place, creating a mechanical seal that not only fixes the leak but rebuilds the seal. The system is portable enough to fit into a briefcase. The fully mobile system allows leak work to be done from the top of the wellhead down without removing the wellhead itself. Leaks are found and fixed through the annulus or tubing of a well, enabling shut-in wells to come back online or to full production within hours rather than months. In the time it can take to plan one rig workover, the system can address integrity issues in more than 100 wells. The technology, which has been used to fix tubing, connection, and casing leaks, is building an extensive track record, achieving a 100% success rate since April 2009.

Technology in action
The technology recently was used to seal casing leaks in a number of wells approximately 30 miles (48 km) west of Prudhoe Bay. The Greater Kuparuk area includes the Kuparuk reservoir as well as several smaller oil pools in the operating unit. The majority of the wells are completed with a conductor casing (CC), a surface casing (SC), a production casing, and tubing.

In one of the wells, a 0.25-inch corrosion- induced hole in the surface casing at a depth of 126 ft (38.4 m) was sealed with a single platelet by a deployment from surface into the outer annulus. The well initially was leaking at a rate of 0.5 bbl/min and subsequently passed a 1,800 psi mechanical test integrity.

Records indicate that near-surface casing corrosion is a result of a cyclic or consistent ingress of oxygenated water into the annulus between the CC and the SC. Elevated well operating temperatures in conjunction with an extremely corrosive environment caused by soluble salts that leach from the cement create a very aggressive corrosion environment. Over the years, 53 wells have exhibited SC corrosion failures at shallow depths. Limited options for accessing and repairing the leak sites prompted the operator’s interest in pursuing the new technology.

A number of wells were identified in the field as potentially suitable for the application of the sealing technology. The first phase of the project was the front-end development of a low-temperature solution (down to 5ºF or 15ºC) and detailed job design, including wellsite leak rate testing, material testing, computational fluid dynamics modeling, and flowloop testing. The second phase was the onsite application of the platelets.

Platelets were deployed into the injection tree at a rate of 1 bbl/min. After 2.5 min., the pressure began to increase, indicating platelet entrainment. The pressure was increased in 500 psi increments and held for five minutes at each step. When 1,800 psi was reached, a standard mechanical integrity test of the SC was completed and then extended for an additional 30 min., which confirmed a 100% effective seal. The pressure was bled back in steps to a final static closed-in pressure of 500 psi.

The solution was achieved without having to excavate and remove the surface conductor or pull the tubing and cut and pull the casing.

Post-seal restrictions suggested maintaining positive pressure on the annulus in which the platelets were deployed to ensure the platelet stays in place and maintains seal integrity. Following the successful platelet seal, however, the SC pressure was twice inadvertently allowed to drop to zero due to thermal cooling, and no adverse effects were experienced on the seal. This indicates the sealing platelet could maintain a seal under only hydrostatic head (45 psi). Therefore, the higher SC operating pressure is insurance but might not be required.

Using this technology, the well was brought back to a serviceable state in a shorter time than a conventional process would require. The entire operation was carried out in six hours.