The deposition of carbonate and sulphate scales is a major problem during oil and gas production. Managing scale with chemical application methods involving either scale prevention and/or removal are the preferred methods of maintaining well production. However, chemical scale control is not always an option, depending upon the nature of the reservoir and well completion and, in cases of severe scaling, the problem can render chemical treatments uneconomic unless other non-chemical methods are utilised.
A variety of non-chemical scale control methods exist, the most common being injection of low salinity brines or low sulphate seawater (LSSW) using reverse osmosis and a sulphate removal plant (SRP) respectively. In addition, careful mixing of lift gas, produced waters and reinjection, coatings, smart well completions with active inflow control devices (ICD) and sliding sleeves (SS) are other methods.
All of these techniques, including combinations thereof, are currently in use and the advantages and disadvantages of the key techniques are compared to chemical methods for both carbonate and sulphate scale control. A detailed example from a North Sea field demonstrates where downhole chemical scale control has not been required through a strategy of careful mixing of lift gas, brines and produced water re-injection. This was combined with understanding fluid flow paths in the reservoir and their likely breakthrough at production wells.
Consideration is given to the injection of smart brines to scale deep in the reservoir, and data from North Sea chalk fields shows how "
This paper presents a comprehensive review of non-chemical methods for downhole scale control and discusses how the use of these techniques can provide alternative scale management strategies through minimising or alleviating the need for downhole chemical treatments.
Formation of sulphate and carbonate scale is well understood within the hydrocarbon extraction industry with injection of incompatible water such as seawater into reservoir with significant concentration of barium, strontium and calcium. To overcome this challenge chemical inhibition has been utilized for many decades and in the past 15 years elimination/reduction of the sulphate ion source from injection seawater using sulphate reduction membranes has been employed. This paper present laboratory work to qualify a scale inhibitor and field results of its application to prevent scale formation when an operator had to change from low sulphate seawater (LSSW) mixed with produced water (PW) for their water injection source to a blend of LSSW/PW and full sulphate seawater (SW). The increased level of sulphate presented a significant scale risk within the topside process on fluid mixing but more significantly increased the risk of scale formation within the near wellbore region of the injector wells which were under matrix injection rather than fracture flow regime. The qualification of a suitable inhibitor required assessment of the retention of a potentially suitable vinyl sulphonate co polymer scale inhibitors to ensure it had low adsorption and was able to propagate deep into the formation before being adsorbed from the supersaturated brine. Coreflood studies using reservoir core were carried out to assess the scale risk of the LSSW/PW/SW brine, propagation and release characteristic of the short-listed scale inhibitors. The recommendation that followed the laboratory studies was to apply a batch treatment of concentrated scale inhibitor to each injector well to provide a high concentration pad of scale inhibitor that would be transported into the reservoir when the scaling LSSW/PW/SW fluid was injected. Protection was provided by continuous application of the same chemical at minimum inhibitor concentration to prevent scale formation within the topside and the desorption of the batched inhibitor within the near wellbore would prevent scale formation within this critical region. Thirteen injection wells were treated with a pad of 10% vinyl sulphonate co polymer scale inhibitor to a radial distance of 3 ft.
An increasing number of Floating Production, Storage and Offloading Platforms (FPSO) are currently entering a mature age, requiring costly maintenance operations. Maintenance cost of the shipping industry is partly linked to corrosion management of the structural parts (incl. hull) while "Crop & Renew" of super tankers is usually taken care of during dry dock operations: FPSO hulls shall be maintained "on the field" creating challenges in terms of safety and economics. Indeed, for safety concerns, hot works on FPSO may yield to high risk simultaneous operations (SIMOPS) and/or production disruption. FPSO operators have therefore been looking for "cold work" solutions that guarantee safe and economical hull repair. This paper presents an innovative cold repair solution called ColdShield for the permanent reinforcement of steel structures in such marine environment. The purpose of ColdShield is to strengthen - in a safe and controlled manner - corroded offshore structures by eradicating the use of hot works during the whole repair process, thus avoiding downtime. The technology is based on proven techniques of bonded composite reinforcement already used in other industries such as aerospace and civil engineering. This innovation was led by COLD PAD with the support of Total, the French Petroleum Institute, and involved four different private and public laboratories.
The paper describes how this innovative technology has marinized composite reinforcement techniques throughout the three critical stages: design, installation and service life. Classical bonded composite reinforcements are usually limited by their high sensitivity to environmental marine conditions. As water is a severe degradation factor of bonded interfaces, it is well-known that bonding process in high humidity conditions, such as marine environmentswhere FPSO hulls typically are, leads to poor adhesion properties and a premature ageing of bonded reinforcements.
This led to a series of tests and simulations to finally obtain the class approval for ColdShield for hull girder strength by Bureau Veritas as a certified alternative to crop & renew.
The paper covers two field cases in West Africa comparing ColdShield with standard techniques in terms of safety, planning and savings. With an ageing fleet, the FPSO industry will face more and more corrosion challenges and COLDSHIELD proves to be a suitable tool to lower risks and costs while maximizing safety.
Mooring tensioning systems for offshore floaters have evolved from rotary windlasses on ships into multiple options nowadays. These options include fixed or movable winches, either linear or rotary, driven by electric or hydraulic, and the most recent in-line tensioners which remove the on-vessel equipment. Selection of a tensioning system directly affects mooring performance and installation, hull design, as well as overall project cost, schedule, operability and reliability. This paper compares a combination of seven types of tensioning system for the mooring system of a deepwater platform. The options under consideration for the tensioning system include fixed or movable, electric or hydraulic driven, and on-hull or in-line tensioner. The pros and cons of different alternatives are evaluated in terms of design, installation, and operating considerations, and are compared against criteria including Technology Readiness, Cost and Schedule, Installation, Layout, Maintenance, In-service Tension Adjustment, HSSE (Health Safety Security Environment) Risk, and Track Record.
It is found that all options, fixed or movable, electric or hydraulic driven, and on-vessel or in-line tensioners have their advantages and disadvantages, and need to be evaluated systematically to fit different projects’ needs. Fixed hydraulic chain jacks remain the most popular choices for production semis, with 12 applications out of 24 since the year 1994. Movable options have merits over fixed ones in capital expenditure, especially with high numbers of lines. However, movable options require extra equipment and operations to relocate the tensioning system and thus have shortcomings in mooring installation, tension adjustment, and HSSE risk. An electric option has advantage in maintenance, because it does not require a HPU and has no hydraulic oil or flexible pipes to be replaced. However, electric options are heavy and large, with complicated gear boxes, and require a specialized team. Without on-hull tensioning and handling systems, the in-line tensioners may significantly reduce capital expenditure. Additionally, they eliminate the notorious problem of splash-zone corrosion since the top chain is completely submerged underwater. However, this system requires surface vessel intervention for tensioning and re-tensioning, and increases project execution and schedule risk. All of these need to be taken into consideration starting from early through execution phases of projects.
As the offshore industry moves forward with emerging new technologies, projects usually involve multiple choices as well as technical uncertainties and financial risks. Most projects with mooring systems will encounter the similar challenges on selecting a reliable and cost effective tensioning system. This paper can serve as a reference for a major capital project that is going to select the most suitable tensioning system. With the state-of-the-art information and industry practice on mooring tensioning systems, this paper can also service as a reference for updating new versions of API and ISO station-keeping codes.
Recently there has been significant interest in the development of seabed trenches associated with anchor chains in front of suction anchors. The issue was first highlighted by
Previous publications relating to anchor chain (mooring line) trenching have focussed primarily on observational case histories (e.g. Serpentina FPSO) and analysis of the impact of seabed trench formation on suction anchor in-place holding capacity. Furthermore, recent work by others outlined the results of 1g and centrifuge model anchor chain tests and the use of these results in the preliminary development of a chain model encompassing the progression of erosion and trench wall collapse with time.
This paper describes a new design tool which permits identification of the primary mechanism leading to the formation of seabed trenches running along the embedded section of mooring lines in front of anchors. The model provides a direct approach to estimating the extent of seabed trench formation that may arise from mooring line motions under both normal (operational) and extreme (storm/cyclonic) conditions. As inputs the design tool requires the full mooring line layout/configuration from the fairlead (located at the floating facility) down to the anchor padeye, the range of design loads at any point along the mooring line and the seabed soil properties.
Through an example study the paper demonstrates the ability of the design tool to back-analyse seabed mooring line trench formation at existing installations and predict the extent to which mooring line trenches may develop for new sites. The ability to perform site-specific assessments of trenching risk should in turn allow the industry to move away from including blanket allowances for trenches which, sometimes unnecessarily, mean that much larger anchors are planned than actually required.
The Girassol, Jasmin, and Rosa fields were discovered in Block 17 in the late 1990s and early 2000s, 210 km northwest of Luanda, Angola, in water depths of approximately 1400 m. The Rosa Field started production in 2007 using a subsea tieback to the Girassol floating, production, storage, and offloading (FPSO) vessel. In anticipation of a plateau decline, the operator studied opportunities to develop marginal resources and improve recovery of mature fields. The Rosa Field emerged as one of the targets for improved oil recovery. It is the farthest from the Girassol FPSO vessel, using up to 20 km of subsea production flowlines. Consequently, the field sees a significant subsea-network-pressure drop, which, combined with an increase in water cut and constraints in topside gas compressor capacity, accelerated the production decline. By removing these limitations, oil production could be increased.
Life extension of offshore assets is a popular and hot topic as Operators are willing to maximize the operation of their platforms in order to increase their economical returns while maintaining satisfactory level of safety and integrity of their asset. The paper will propose a pragmatic, fit for purpose and consistent approach in establishing the baselines for life extension of any type of floating structures: FSO, FPSO, FSRU, FSU, FLNG and FPU.
Most people know the Hybrid Riser Tower solution, combining the use of steel pipes in a freestanding bundle and multiple flexible jumpers for connection to a floating host vessel, from the 3 towers installed in 2001 offshore Angola in 1,350m water depth to the Girassol FPSO. Little known is the fact that the first bundled riser tower, in a slightly different arrangement preceding Girassol, was actually installed by Placid in Green Canyon (1988), and the same riser tower was later redeployed by Ensearch in Garden Banks (1994, now decommissioned), both in the Gulf of Mexico in less than 650m water depth to a semi-submersible production platform.
Dear Colleague: On behalf of the Society of Petroleum Engineers (SPE) and the Conference Programme Committee, we would like to thank all contributors who submitted paper proposals for the SPE International Conference and Exhibition on Health, Safety, Security, Environment, and Social Responsibility, which takes place 11-13 April 2016, in Stavanger, Norway. It's the Baker Hughes way. Protecting people, assets, and the environment is all a part of our purpose: enabling safe affordable energy, improving people's lives. A Perfect HSE Day means no injuries. And it's the way we do business: Oil and gas services rendered through the Perfect HSE Day This edition of the oil and gas industry's premier HSE event celebrates its 25th year.