Flow-Assurance Strategy Manages Subsea Asset Without Continuous MEG Injection
The paper describes options for hydrate and integrity management and the required modifications to both subsea and topside facilities to enable an operational philosophy change.
The Vega field on the Norwegian Continental Shelf has been producing successfully using continuous monoethylene glycol (MEG) injection, topped with means of corrosion inhibition. A topside reclamation process allows reuse of MEG but limits the possibilities of producing saline water. The complete paper presents a discussion of a feasibility study of a new flow-assurance and -integrity philosophy to manage wells without continuous MEG injection. The paper describes options for hydrate and integrity management and the required modifications to both subsea and topside facilities to enable an operational philosophy change.
Current Subsea Flow-Assurance Approaches
Gas-hydrate formation in wet gas flowlines is considered one of the primary challenges seen in subsea assets. Its mitigation requires considerable capital expense and often significant operating expense (OPEX) over field life. Although the thermodynamic stability of the ice-like structures is well understood, the same is not the case for the kinetics of their formation or the dispersion in multiphase systems, which might be a crucial aspect in hydrate plug formation. Traditionally, the approach to hydrate mitigation has been to keep the system outside the hydrate-formation region by various means, including the following:
- Insulation of flowlines or direct heating possibilities
- Depressurization on shutdown
- Hydrate inhibition by thermodynamic or low-dosage hydrate inhibitors
- Subsea separation and drying of gas
For long multiphase flowlines, options are limited. Insulation or direct heating often is uneconomical. Depressurization on shutdown requires significant storage space on a host facility for liquids and leads to massive volumes of flared gas. Subsea separation and gas drying are not yet fully mature, so use of hydrate inhibitors is common.
Hydrate inhibitors can be classified as either thermodynamic or kinetic inhibitors. The latter are also called low-dosage hydrate inhibitors (LDHI) because of the lower concentration required. The main advantage of thermodynamic inhibitors is that they shift the hydrate curve to fully protect the system, whereas the kinetic inhibitors tend to wear off after time, leaving the systems un- or underprotected. However, their use often allows for infrastructure reduction and simplified production operations.
The most typical thermodynamic inhibitors are based on salts (as from the formation water) or alcohols such as methanol, ethanol, or glycols. The advantage of the latter is that their separation from water is technically viable, so they can be used in a recycle, or closed-loop, system, which can only function well in systems free of salinity or with limited saline formation water ingress.
Aging reservoirs tend to increasingly produce saline water. This often forces the need to recomplete or abandon wells before reaching ultimate recovery because the infrastructure is unable to handle the production rate of saline water. As a result, changing flow-assurance philosophies for mature assets are often evaluated. However, changing within the given limitations of an existing infrastructure is a massive endeavor and requires a strong interdisciplinary approach.
The field is a high-temperature, high-pressure gas-condensate/volatile-oil asset in 360 to 380 m of water. It consists of three subsea templates (Vega South, Vega Central, Vega North) with two production wells each. The templates are daisy-chained on a 32-mile-long multiphase flowline to the Gjøa semisubmersible platform as host. The two wells on the three templates drain separate accumulations of gas condensate, all within the Brent group (Fig. 1).
The fields were discovered in 1980 and 1982 by Gulf Exploration and in 1987 by Mobil. Development of Vega North and Vega Central began in 2006 by Norsk Hydro, with Vega South added later. Drainage strategy is depletion drive, focusing on the southernmost wells first. The field began production in late 2010.
Vega hydrate philosophy is based on continuous MEG injection by a 3-in. line, with injection occurring independently at every template’s manifold. Depressurization is required only when a failure in the MEG system is detected or suspected, and as a hydrate-plug-remediation measure. Additionally, wells are designed to be shut automatically in when a failure in the MEG system is detected or suspected. The hydrate inhibition system is a closed loop.
Maturing assets tend to produce increasing amounts of formation water, typically saline. As described in the complete paper, the hydrate strategy for the Vega field relies on continuous MEG injection and regeneration, the latter being bottlenecked by the production of a salinity equivalent to approximately 10 m3 of saline formation water per day. Wells producing above this threshold would be required to be choked back or plugged and recompleted. This had already happened in one well. To increase ultimate recovery and ensure hydrocarbon exploitation with formation water production, a feasibility study was initiated to evaluate possibilities for increased saline-water handling.
The MEG reclamation unit topside Gjøa was soon identified as the bottleneck to increased salt-handling capacity. Any solution that included taking the MEG reclamation unit out of service, however, would have to deal with no possibility to reuse any hydrate inhibitor. This meant their use should be limited to an absolute minimum and best excluded for regular operations, in turn leading to significant changes in asset operation.
To approach the feasibility of an alternative flow-assurance concept without continuous MEG injection, the project was divided into three separate tasks. Task 1 was focused on hydrate management, outlining the risk picture within regular and turn-down production, as well as planned and unplanned shutdowns, and aiming to develop both an alternative hydrate-mitigation strategy and a hydrate-plug-remediation plan for the asset. Task 2 dealt with integrity management under an alternative production strategy. Task 3 involved handling the aqueous phase topside at the host facilities. Most of the complete paper is devoted to extensive technical discussion and graphical illustration of the details of the feasibility study.
Feasibility Study Highlights
After a thorough investigation based on dynamic simulations, historical data, and laboratory tests, it was concluded that the hydrate-plugging risk in the Vega pipeline without any hydrate-mitigation measure was beyond acceptable levels. Therefore, an alternative flow-assurance philosophy for the field had to rely on timely depressurization of the Vega pipeline and/or continuous injection of LDHI. A detailed hydrate-plug-remediation plan to manage the uncertainty associated with a change in hydrate mitigation strategy had to be matured.
Active and reactive hydrate-mitigation measures were investigated. An active measure implies that actions are taken before, during, and after a given event occurs—for example, by continuous hydrate inhibitor injection. A reactive measure denotes that actions are taken only after a given event occurs, such as by depressurization after a long production shutdown. Both types of measures have different advantages and disadvantages that must be properly weighted. Active measures such as continuous hydrate-inhibitor injection typically have higher OPEX than reactive measures, but the residual risk tends to be lower for active measures. The complete paper discusses one reactive concept purely based on pipeline depressurization and two active philosophies based on continuous LDHI injection.
The authors note that these three alternatives are not considered to be isolated, mutually exclusive choices, but rather as a stepwise solution toward the maturation of a final Vega hydrate philosophy, starting with a depressurization concept, then moving toward a continuous kinetic hydrate inhibitor injection philosophy with occasional partial and full depressurization, and finally arriving at a continuous anti-agglomerant.
Two different hydrate-plug-remediation concepts—platform-based and vessel-independent—have been developed to guarantee that the prospective change in Vega’s hydrate philosophy will not result in an unsolvable technical or economical hydrate blockage. Both are described in the complete paper.
The integrity-management task of the feasibility study addressed scaling, integrity, and static and dynamic corrosion testing. Alternatives for handling the aqueous phase topside at the host facilities included debottlenecking the MEG reclamation unit, reducing salinity in aqueous fluid by membrane techniques or desalination, recompleting wells and shutting in water-producing wells, shipping aqueous fluid to an alternative location for reclamation, and disposing aqueous fluid into the sea.
This article, written by JPT Technology Editor Judy Feder, contains highlights of paper SPE 195784, “A New Flow-Assurance Strategy for the Vega Asset: Managing Hydrate and Integrity Risks on a Long Multiphase Flowline of a Norwegian Subsea Asset,” by Stephan Hatscher, SPE, and Luis Ugueto, Wintershall Norge, prepared for the 2019 SPE Offshore Europe Conference and Exhibition, Aberdeen, 3–6 September. The paper has not been peer reviewed.