TX 75083-3836, U.S.A., fax 01-972-952-9435. AbstractPressure leaks in a wellhead or in downhole tubulars or equipment can lead to inoperable subsurface safety valves, casing pressure, environmental pollution, loss of production and, in extreme cases, blowouts. As such, it is essential to the safe and environmentally sound operation of a well that the sources of the pressure leaks be identified and cured. Use of a new and unique pressure activated sealant technology allows utilization of a method of repairing wellhead and downhole leaks in-situ without employing any mechanical downhole operations. Only at the point of differential pressure, through the leak site, will the sealant reaction occur and create a bond across the leak. Use of the pressure activated sealant technology obviates the need to employ expensive and risky rig or wireline operations to cure downhole leaks.

TX 75083-3836, U.S.A., fax 01-972-952-9435. AbstractA cost-effective method of internally repairing pipeline leaks has been developed that -in many instances -eliminates the need for expensive and risky external mechanical repairs.By delivering a pressure-activated sealant between two pigs to a leak site and pressure activating the sealant to polymerize as a flexible solid within the leak path, it is possible to internally repair pipeline leaks without the need for excavating or replacing defective sections with minor leaks.

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Sustained casing pressure is a serious problem that is prevalent in most of the oil producing regions of the world. Annular pressure can be a significant safety hazard and, on a number of occasions, has resulted in blowouts. Sustained casing pressure results from the migration of fluids in the annulus. The most common path for migration of fluids is through channels in the annular cement. To safely and economically eliminate sustained casing pressure on a well in the Gulf of Mexico, W&T Offshore, Inc. utilized an injectable pressure-activated sealant technology to seal channels in the annular cement of their well and eliminate the casing pressure. The mechanical integrity of the well was restored, saving over $1,000,000 compared to a conventional rig workover. Introduction Migration of fluids through the annuli of wellbores can result in a condition known as "sustained casing pressure" or "SCP". SCP is pressure that rebuilds in the annulus after being bled down.1 With age, the integrity of all wellbores deteriorate. Cracks and fissures develop in the annular cement due to a number of factors related to cement composition, thermal stress, hydraulic stress, compaction, wellbore tubulars, and the downhole environment. The most significant cause of sustained casing pressure in the outer casing strings is a poor cement bond that results in the development of cracks and annular channels.2 The cracks and microannulus channels through the cement provide a path for high-pressure fluids to migrate from deeper strata to low-pressure strata or to the surface. If left uncontrolled, SCP represents an ongoing safety hazard and can cause serious or immediate harm or damage to human life, the marine and coastal environment, and property.3 A significant flow of high-pressure fluids to a low-pressure strata results in an underground blowout. A significant flow of high-pressure fluids to the surface results in an irreducible casing pressure at the wellhead and the potential for catastrophic failure of wellbore integrity. SCP is a pervasive problem for the oil and gas industry. According to the records of the Minerals Management Service ("MMS") of the United States Department of the Interior, SCP affects over 8,000 wells in the Gulf of Mexico.4 Conventional Remediation Risks The conventional remedy for outer casing SCP is to perform an expensive and risky workover of the well using a rig. In the past, the industry has been reluctant to cure SCP problems on most wells based on a cost/benefit analysis of the relative risks. A conventional rig workover is a dangerous operation. Personnel can be injured or killed. Equipment can be damaged or destroyed. Blowouts or spills pose a significant environmental risk. The costs and risks of the conventional rig workover solution exceed the costs and risks associated with the current sustained casing pressure practices.5 The rig workover procedure requires removal of the tubing and injection or squeezing cement in an attempt to block the cracks and channels through the annular cement. Depending on the location, porosity and permeability of the cracks and channels, the cement squeeze may or may not be successful in sealing the paths for the migration of the fluid through the annulus. A cement squeeze is a costly procedure with a questionable probability of success. Cost-Effective Alternative As an alternative to a rig workover, a safe, cost-effective sealant process has been developed that eliminates the SCP by sealing the annular channels that provide the paths for the migration of the fluid through the annulus. Tests and actual job histories have shown that this sealant can be injected into the annular channels even after attempted injection with normal mud / cement mixtures have failed.

The paper describes the use of a pressure activated sealant technology to cure leaks in subsea wellbore equipment and control systems. The benefit of this technology is that use of an injectable pressure activated sealant to cure leaks provides a safe, cost-effective alternative to conventional well interventions. The paper outlines the capabilities of the pressure-activated sealants, the procedures used and the results of the sealant operations including case histories. Introduction As the industry moves into deeper waters, the capabilities of subsea wellbore equipment and control systems are severely tested. In spite of great advances in engineering, the complexity of the systems and the number of individual components in deepwater systems create numerous potential leak sites. Leaks can result in abnormal pressures in the wellbore equipment and control systems or releases of control fluids, oil, gas or other fluids. These leaks create issues of safety, environmental protection and cost. The costs of well interventions rise dramatically with depth. Over the life of a deepwater well, the costs and risks of conventional well operations can be prohibitive. In analyzing the long-term costs of subsea operations, the industry must investigate new intervention technologies to repair leaking subsea wellbore equipment and control systems in-situ without the need of mobilizing expensive and risky intervention operations. Common Subsea Failures Over the life of a subsea system, it is possible for a leak to occur in most of the components of a subsea well system. Connection leaks are found in umbilical lines, hydraulic lines, control systems, flow hubs, tubing, casing and similar components. Dynamic seal leaks are experienced in SCSSVs, actuators, valves control systems and similar components. Static seal leaks are seen in wellheads, packers, hangers and similar components. Downhole leak sources include tubing, casing, packers, sleeves and other components. During installation, damage to components can create a variety of leak sources. Sealant repairs have been performed on most of the above-listed components. Subsea Leaks-The Problems Analyzing and repairing leaking subsea systems is complicated by the remoteness of the equipment, the uniqueness of many of the subsea installations and the logistics of delivering a solution. Once installed, you can't put you hands on the hardware. The only means of analyzing leaks is through remote diagnostics - often limited to simply taking pressure readings. Further, many of the subsea systems have no service history, so there is no historical data to assist in diagnostics. Even if the problem is identified, the question is how do you deliver a solution? Do you use a rig, divers, ROV or some other method? What are the regulatory issues raised by the leak? As an engineer evaluates solutions to the problems created by leaks, a first step is an analysis of the problem followed by a review of the options. Traditionally, the solution has been a mechanical workover of the well including replacement of well components. Considerations include availability of a rig, service company availability and coordination, replacement equipment, the cost of all of these factors and the impact of lost production. Traditional Mechanical Repair Methods When repairing a subsea leak, traditional mechanical repair methods become much more complicated and expensive. Whereas repairs to platform equipment (such as a loose fitting) can be accomplished with a simple turn of a wrench, mechanical repair of a leak at a depth of 1,000 meters requires considering some very different repair options - including some very risky, complex and expensive options. The direct costs of any subsea repair operation can be in the millions of dollars. Beyond the direct costs of the mechanical repair options, an operator must take into consideration the risk-adjusted costs of the operations. The problems with most traditional mechanical repair options are as follows:The operation requires considerable engineering and scheduling preparations.The operation requires an expensive, complex multi-service vessel or rig.