GATE was engaged to evaluate the current condition and remaining life of the subsea jumpers and flowline of a deepwater oil and gas facility in the Gulf of Mexico.
The subsea field, which was comprised of multiple oil wells, was produced at a Tension Leg Platform (TLP) with a nominal capacity to produce 100,000 barrels of oil and 50 million cubic feet of gas per day. The subsea and topsides facilities were designed to operate with an expected maximum carbon dioxide (CO2) concentration of 0.15 mole percent from any given producing well.
A facility that processes hydrocarbons needs an inspection program not only to meet regulatory requirements, but also to protect its bottom line by actively managing risk. While this goal may be a foregone conclusion, its achievement is not. So, what goes into a well-designed inspection program? And what does it produce? How can the most value be derived from inspection dollars?
As a part of their regulatory remit, BSEE is undertaking inspections to ensure the integrity of the structures and processing equipment on the OCS are properly maintained to continue safe operations with no harm to the environment. As a part of this undertaking both scheduled annual inspections, and periodic and unannounced inspections are performed.
There are many production reservoirs that produce high levels of hydrogen sulfide (H2S). Some of these fields know before initial production that there will be high levels of H2S and thus are able to design and manage accordingly; however, some fields will begin producing an increasing amount of H2S following water injection. These fields are more difficult to manage and require a means of prediction to help make cost-effective project decisions. At GATE Energy, we have the technical knowledge and experience to apply our own approach to souring prediction which can enable design and operational decisions to be made to mitigate the risks associated with such H2S production.
There are many projects that leverage water injection or waterflood (WF) as a secondary recovery tool to increase oil production returns. Many of these projects’ economic viability is intrinsically linked to the ability to inject large volumes of water into the reservoir as a means of oil drive and pressure maintenance. For these fields, it is vital that the integrity of the water injection system is maintained through fit-for-purpose material selection and asset integrity management processes.
After an in-line inspection of a pipeline in West Africa, a client discovered significant wall loss in the first three miles of the line. The tool also returned significant wax deposits, casting doubt on the current wax management efforts in place.
The wells producing to the pipeline historically produced H2S; however, the worst offenders were shut-in quickly after it was discovered that they were producing extremely high concentrations of the sour gas.
As part of a recent asset acquisition due diligence, GATE was asked to deliver a third party review of the condition of the asset and remaining production life of a floating production system and a fixed jacket.
GATE developed a standardized work process to evaluate the current condition, potential production bottlenecks and future operating expenditure (OPEX) associated with the brown-field producing asset.
The review of the remaining cathodic protection (CP) life of a Gulf of Mexico tension-leg platform (TLP) was undertaken to evaluate the ability of the current systems to support a 20-year life extension. At the same time, the opportunity to include non-destructive riser testing into the life extension program was also identified.
During the fabrication of the subsea boarding valve skid for a major offshore platform in the Gulf of Mexico, the fabricator purchased several large forgings. These large forgings, from 8” to 12” in diameter, were to be machined into block valve bodies rated to 15,000 psig. As part of the agreed-upon Inspection and Test Plan, the mill certificates for the forgings were reviewed by the fabricator and by the company inspector.
A Louisiana operator experienced integrity issues with an existing 3 inch saltwater disposal pipeline. Production history recorded multiple leaks in the existing pipe, which resulted in environmental remediation. Upon investigation the operator determined that the said discharge pipe was unsuitable for future use. BlueFin was sought to review the situation and develop a plan of action that would resolve the integrity issues.
A steam generating plant supporting an associated thermal recovery project in the Middle East was experiencing through-wall corrosion of carbon steel lines. In some locations this was aggressive enough to corrode through replacement piping in as little as two months. Downtime in the steam plant was reducing heavy oil production and increasing OPEX. GATE was invited to the site to take a closer look at the operation and management of the system and determine how corrosion could be more effectively controlled.
GATE was consulted to identify the source of unexpected levels of H2S that had been detected in the central processing facility. Ultimately, GATE was able to determine that multiple operational issues needed to be addressed to mitigate the high levels of H2S in the processing facility, rather than the H2S naturally occurring in the reservoir.
A large and complex offshore field in the Middle East was suffering from multiple leaks due to corrosion in the presence of high levels of CO2 and H2S in the production, seawater injection, aquifer water injection and produced water injection systems. This was resulting in excessive chemical injection expenditures and was impacting field revenues and uptime. The large, shallow water field consisted of several hundred wells and a complex hub and spoke infrastructure.
A South American operator developed plans to return a sulfur recovery unit to service after an initial ten years of service and a further ten years of mothballing due to changes in field production requirements.
The corrosive nature of molten sulfur, carbon dioxide and hydrogen sulfide in the unit, coupled with the expectation of a less than optimum preservation strategy in a littoral offshore environment, generated a large set of integrity risks that needed to be evaluated to determine the feasibility of repairing and reinstating the system for a further ten years of service.
Development of an integrity management program is initiated during design phase, which includes selecting the appropriate materials, establishing requirements for corrosion, erosion, flow assurance and process along with associated maintenance, monitoring and surveillance requirements. In this GATEKEEPER, the philosophy around the materials selection and corrosion monitoring is discussed as the primary design barrier to corrosion and cracking in critical parts of a subsea system.
A midstream company operating a high pressure gas pipeline required assessment services in order to maintain regulatory compliance. The said pipeline asset was considered unpiggable for ILI technology. In order to comply with regulatory guidelines for an MAOP verification, the company demanded a hydrostatic pressure test assessment.
A GoM operator witnessed a leaking 6” pipeline. Upon repairing the visual leak and attempting to perform a successful hydrostatic pressure test a second non-visual leak occurred, ultimately resulting in extended production loss.
In order to perform a second assessment and bring production back online, the pipeline assessment required a 100% fluidpacked volume of seawater to ensure an oxygen-free environment.
A Gulf of Mexico (GoM) operator in the process of decommissioning one of its fields requested the engineering assessment of a blockage existing in their flowline-riser. The reservoir fluid characteristics and the field’s operational history were extensively reviewed. The review indicated hydrates to be the likely cause of the blockage.
A GoM operator witnessed increased differential pipeline pressures on multiple production flowlines in a single field. Field history and maintenance projects indicated paraffin and asphaltene deposition. Routine measures to solve this particular flow assurance problem compromised conventional production chemical applications. While such chemical injection and batch solvent treatments provided resolution by retarding deposition, minimal mitigation resulted and no increase of production was achieved.
As a result of paraffin deposition, a GoM operator experienced increased differential pressures in a bulk crude sales pipeline. Historical line maintenance followed normal production chemical treatment. Once pipeline differential pressures reached an alarming level, it was proven that conventional chemical treatment recommendations failed to protect the pipeline or mitigate the ongoing issue. In addition to increasing differential pipeline pressure, depositional shearing became a valid concern and threat to total pipeline plug off.
A West Africa field operator witnessed an abnormal increase in pressure topsides when the flowline circulation pump was used to pump dead oil into the production line. No increase in subsea pressure was observed. Operational history prior to blockage hinted at the possibility of the presence of one or both wax and hydrate blockages in the production line. Depressurization options were limited by the blocked gas lift line.
American Petroleum Institute (API) 5CT high strength steels are extensively used for casing strings in wells subjected to high cyclic hydraulic fracturing loads. While non-sour grades of API steel such as P110 casing strings have been used satisfactorily for well construction, standard API P110 connections have seen higher rates of failures than pipe body failures in shale wells that require hydraulic fracturing. P110 pipe body and connection failures have also been experienced in cases where poor manufacturing practices have been employed to produce P110 steel casings and connections used in wells subjected to these high hydraulic fracturing loads.
Martensitic stainless steels continue to be one of the most widely used corrosion resistant alloys in oil and gas developments. Determining if a martensitic stainless steel is acceptable in an unproven environment requires testing to confirm, but predicting the outcome of a given test environment is often initially based on personal experience rather than a qualitative and quantitative assessment.
Triaxial evaluation of wellbore loads is used extensively for casing and tubing string design and analysis. A triaxial based collapse strength method was recently adopted by the American Petroleum Institute (API), and an addendum issued to API Technical Report 5C3 (TR 5C3). The triaxial based collapse formula incorporates internal pressure and axial load into the calculation of casing and tubing collapse strengths. Casing and tubing that are subjected to combined loads have higher collapse strength than previous formulas would predict, permitting the use of thinner walled, or lower strength, pipe than formerly required.
Annulus Pressure Management refers to an engineered approach ensuring that casing annulus pressures do not challenge the well’s integrity during the life of the well. The aim is to maintain the casing pressure within the well’s mechanical design limits at all times by controlling the ‘A’ annulus pressure.