The natural decline in the reservoir energy will impact the flowrate of oil, gas or water, thereby creating instabilities and resulting in decreased production. Artificial lift is used in oil-dominated or liquid-loaded gas systems to increase and stabilize hydrocarbon production, as well as to minimize flow assurance and operational risks, such as slugging in the subsea production system. Artificial lift methods transfer energy to the produced fluid with the objectives of reducing the fluid density and the pressure head or boosting the flowing pressure.
This GATEKEEPER discusses an effective subsea tree PWV (USV) leak test method. The test can be done quickly – entire test time is about 15 minutes, including the 5 minute monitoring time. More importantly, the test gives repeatable, unambiguous results that are easy to interpret and it can be done easily during any well shutdown.
The increased use of dynamic risers as an enabling technology for the movement of the oil and gas industry into the deepwater basins of the world has presented new technical challenges related to the prevention of corrosion failures and other forms of degradation. This has been particularly evident when considering production from the next generation of high pressure/ high temperature (HP/HT) subsea developments in locations such as the Lower Tertiary trend in the Gulf of Mexico. In order to avoid potential riser failures or replacement campaigns for anticipated service lives that may extend to 30 years or more, process facility components such as risers and flowline systems must now be subjected to more enhanced integrity monitoring through the whole of their service life.
Utilized in a number of configurations, a riser presents the operator with a conduit that serves as the main method of hydrocarbon transport from the ocean floor to the host facility as well as a method of external media introduction such as chemical and water injection. Considering the large number of applications that risers have, as well as the dynamic environment associated with subsea oil and gas exploration, it comes as no surprise that the down selection of various riser designs can be a complex process requiring extensive knowledge of each riser style. To aid in this design process, a number of standards have been developed to ensure safe practices throughout design and installation. Such standards and recommended practices can be seen in API RP 2RD, API RP 1111, ASME B31.4 and ASME B31.8 which should be utilized to keep safety at the forefront of the design.
Introduction Wells can be organized into three primary categories: production, injection, and conversion/turn-around. Material selection must be tailored to each well type, as each offers unique challenges from a materials performance perspective.
Tubing and casing are critical to the production of oil and gas and well integrity. Reservoir fluids flowing through the production tubing are often corrosive, making necessary the use of corrosion resistant alloys (CRA) offshore.
Subsea Integrity Management is defined as the management of a subsea system or asset to ensure that it delivers the design requirements while not adversely affecting life or the health of the environment throughout the required life of the field¹.
Operators and chemical vendors responsible for chemical delivery to subsea developments are aware that the use of chemicals with unacceptable solids loadings can result in the plugging of injection lines, subsea metering systems, subsea connectors, and downhole injection locations. However, there is relatively little agreement across the industry regarding the exact chemical cleanliness specifications that need to be applied.
For most offshore facilities and subsea components such as trees and manifolds, carbon steel is a common material of construction. Effective external corrosion control is essential for the longevity and safe operation of these components.
For long-term external corrosion protection of subsea steel components, cathodic protection (CP) along with corrosion coatings are commonly used. As the offshore environment moves into deeper waters, the cost of interventions subsequently increases. Therefore, the engineer is challenged with balancing a highly reliable CP system, sometimes achieved with excess anode mass, with CAPEX and weight restrictions. The optimal CP system will need to minimize weight and cost and maximize reliability.