This paper will share the experience in the development of an online mercury measurement system for high pressure liquid hydrocarbon streams. It focuses on challenges in handling high pressure volatile hydrocarbon, impurities associated with the matrix, particulates, water and mercury concentration. Challenges associated with assurance in sample representativeness, and validation complete with automation are also discussed. The project was initiated to reduce cost of current offline mercury analysis, the need to minimize analytical error, expedite acquisition of analytical results, and minimize personnel exposure to mercury during manual sampling and analysis.
In addition, the determination of mercury in natural gas and condensate is made difficult by the very low concentrations involved, the highly volatile nature of mercury and the complexity of the sample matrix. This dictates that either a highly sensitive detector or a large sample volume or both are needed to perform adequate analysis. A variety of techniques with different sensitivities are presently available for the determination of mercury. The system developed consists of 4 main modules; sample pretreatment, sample capture, sample conditioning and mercury measurement (i.e. detection system). The detection system utilizes a spectroscopic technique for mercury analysis hyphenated with in-house developed liquid hydrocarbon conversion system and sampling system. Results gained from performance testing demonstrate good reliability and opens new prospects to further develop the system for other facilities where mercury monitoring is required, especially for remote facilities.
Novel well completion technique is used to ensure dual tubing performed under fatigue condition in Field B TLP. Based on initial tubing stress analyses, the dual strings are under compression during production. Also due to the Single Combo Top Tension Riser (SCTTR) design, first in the industry, the riser must be isolated from hydrocarbon flow. All 10 producers completed to date were tensioned successfully using this technique. This paper discusses various methods of string tensioning and executing the completion.
Flow assurance problems related to flow slugging, hydrates, and wax gelling lead to this study, post two integrated oil pipelines clogged in the Caspian Sea during the winter season. The methods and proposed solutions will be further deliberate, which includes the development of operating envelope to ease implementation. The overall methodology is based on dynamic flow assurance simulation and mathematical analysis, which was adapted depending on the problem being studied. Reduced production and terrain undulations had caused severe slugging in both pipelines which are flowing multiphase fluids. The bifurcation analysis of slug control valve will be discussed to determine the best choke opening that can eliminate slugging. The flow slugging also caused hydrate risk that was made worst during shutdown. Few strategies of hydrate mitigation including implementing extra heat insulation at riser air gap, gas flaring, optimised and overdose injection of mono ethylene glycol (MEG) were considered. Hydrate mass was evaluated for all the mitigations and requirement to inject lean MEG immediately after shutdown or prior start-up was identified. In terms of wax management, lower Flowing Tubing Head Temperature (FTHT) from wells added a challenge with limited facilities capability to operate more than the wax appearance temperature (WAT). Operating envelope of crude oil heater under heating limitation will be clearly shown to avoid operating in wax region. The development of operating envelope had enabled Operations personnel to know the safe condition to operate both pipelines during critical scenarios. The approach has changed the way the company operates, to ensure production is protected and maintained with minimal disruption caused by slugging, hydrate and wax gelling events.
The Thermoplastic Composite Pipe (TCP) has been established for a number of years as a viable alternative to steel and flexible pipe in subsea applications, with various intervention type of applications building track record in the field. After the successful installation of a Thermoplastic Composite Pipe for permanent methanol injection on Chevron's high-pressure Alder field in the North Sea in September 2016, Airborne Oil & Gas moved forward with the installation of a flowline for a full well stream application.
The selection of a TCP Flowline ensures a CAPEX reduction as it is manufactured in long continuous length up to 6000 meter and reeled on lightweight transport /installation reels. This allows for reel-lay or surface tow installation with a low-cost installation spread, contrary to steel pipeline requiring slow lay-barges. Furthermore, the TCP flowline can be terminated on the platform and pulled through the I or J tube without the end-fitting, allowing for small and light I or J tubes. The TCP Flowline can be installed in a single pass, optionally with a weight coating to achieve on-bottom-stability and immediate burial with for example a jet trencher if required. This single vessel installation results in the lowest material and installation cost for TCP Flowline compared to the alternatives.
Besides the CAPEX reduction, the selection of TCP flowlines ensures a significant OPEX reduction. Integrity management and corrosion prevention in particular have significant impact on operational cost. This is the case for new developments that more often see increasingly challenging environments with H2S, CO2, MIC etc, but also for existing operations that face unplanned shut-downs and repair cost caused by corrosion.
The fully bonded TCP Flowline has significant advantages. The TCP does not corrode, has a smooth bore featuring low pressure drop, is collapse resistant to large water depth and combines pressure and tensile strengths with spoolability. The unique and specific properties of TCP make it a cost effective choice for a variety of different applications, from shallow water flowlines, to flexible high pressure jumper spools and deepwater risers.
In the recent years, offshore wind energy has gained much importance owing to its viability and technical advances in the performance predictions. The thirst for steady energy supply from wind has pushed the wind turbine industry to offshore waters requiring floaters as the only possible and feasible solution. The floater along with wind turbine sets up the basis for any offshore floating wind turbines. The costs and the complexity involved in yaw mechanism are very high. To tackle this issue, a weathervane wind turbine system is proposed to eliminate the use of turbine yaw mechanism. In the concept of weathervane wind turbines, the floating wind turbine is connected to a single point mooring (SPM) about which it weathervanes. To better understand and to make practical decisions in real scenarios, performance analysis is carried out for a weathervane wind turbine system of a semisubmersible type. For present study, NREL 1.5 MW wind turbine is chosen as it is readily available and is widely preferred for preliminary studies. The numerical simulations are carried out using effective coupling of FAST code with OrcaFlex. The responses of the floating wind turbine systems not only depend on the floater but also on the coupled motions of wind turbine with SPM subjected to turbulence wind loadings. This non-linear coupling is analyzed in the time domain combining the effects of floater hydrodynamics, wind turbine system and mooring system. Numerical results along with discussions are presented. This preliminary global performance analysis gives a vision on its capability to better suit offshore, meeting the global standards.
Yong, H. Y. (Universiti Teknologi PETRONAS) | Liew, M. S. (Universiti Teknologi PETRONAS) | Ovinis, M. (Universiti Teknologi PETRONAS) | Danyaro, K. U. (Universiti Teknologi PETRONAS) | Lim, E. S. (Universiti Teknologi PETRONAS)
A Free Standing Drilling Riser (FSDR) is a modification to drilling risers that enables rapid disconnection in an event of a typhoon. Air cans were installed to keep the drilling riser standing upright at its original location whilst the drilling rig sails away to safety. This mechanism can be used during a typhoon event as pulling back the whole riser string is a time exhaustive procedure. Typhoon occurring from distant seas can generate strong long period swell. Despite numerous studies on FSDR mechanism, the effect of typhoon generated swell on FSDR have not been reported. The objective of this paper is to study the hydrodynamic response of the FSDR mechanism under typhoon generated swell. Four sensitivity analysis based on swell height, swell period, wind wave height and wind wave period were conducted in Orcaflex10.1c finite element modelling software. The results shown that FSDR mechanism were reliable under typhoon generated swell. With the increase in swell height and swell period, the FSDR hydrodynamic response (lateral displacement, bending moment and von Mises stresses) increases. Since the disconnected FSDR was located out of the wave impact zone, increase in wind wave height and period have little to no effect on the hydrodynamic response.
Enhanced Oil Recovery (EOR) is one of the focus area for Malaysia's offshore oilfield (
Larsen, David Selvåg (Baker Hughes a GE company) | Boesing, David (Baker Hughes a GE company) | Hartmann, Andreas (Baker Hughes a GE company) | Martakov, Sergey (Baker Hughes a GE company) | Mumtaz, Asim (Baker Hughes a GE company) | Skillings, Jon (Baker Hughes a GE company) | Vianna, Armando (Baker Hughes a GE company)
The opportunity to detect boundaries ahead of the bit has long been a desire within the oil and gas industry as it would allow precise geo-stopping prior to entering unwanted formations and/or fluids. There are solutions already available such as the use of seismic applications. However these are for use on a different resolution scale, the accuracy needed for geo-stopping within meters of a formation boundary is lacking.
Extra Deep Azimuthal Resistivity (EDAR) has been widely used for geosteering and landing applications around the world utilizing the common methodology of looking around and predicting ahead (see, for example,
In this paper we will study the extended capabilities of the interpretation method currently used only in high angle and horizontal (HA/HZ) well applications. We will present sensitivity analysis of the theoretical capability of detecting ahead of bit with the different key factors determining the capability, such as sensor placement behind bit, formation resistivity and incident angle.
The study will show that the application range of EDAR can be extended from the 15° incident angle range to up to 90° incident angle. The extension allows using the service for low angle geo-stopping applications. The analysis is performed on theoretical data as well as a case study from a well in the Middle East.
The subject of this study is a Subsea Production System comprising of two (2) subsea gas production wells. The gas, condensate and water from the wells are sent to a processing platform via 4.71 km 24" subsea pipeline. The two wells are independently connected to a production manifold with 12" branch lines and 2 off 12" headers, each with its own dedicated HIPPS module (as shown in
The operation of the subsea facilities is monitored, controlled and operated from a Central Processing Platform (CPP), through electro-hydraulic-chemical umbilical running to the two subsea wells. Utilities for subsea facilities (e.g. electrical power, chemical injection and hydraulic fluid) are also supplied from the CPP.
A Full Field Review (FFR) study has been conducted to identify and implement (as far as possible) opportunities for increasing production and improving recovery factor, maximizing asset value of the subsea field. At time of writing a detailed facility evaluation is being performed as part of the Full Facility Review. The result and findings from the FFR form the basis for future development, identifying potential bottlenecks, key risk or opportunity areas on existing facilities.
Quantifying the hydrodynamic motions of a floating facility is critical for ensuring its safe and efficient operation. The ability to obtain estimates of the motion response charactersitics using a numerical approach to estimate the seastate is particulary attractive for sites in which limited observational wave data are available. Validation of such a numerial approach using full-scale data is however, desirable in order to establish its accuracy and limitations. To this end, this paper presents a case study where numerical estimates of the dynamic motions of a drillship were validated using high quality dynamic motion records acquired during the drilling campaign. The model comprises a hindcast of the directional wave spectra and numerically derived hydrodynamic response characteristics of the ship. The performance of the model is evaluated using a range of selected seastates which were observed during the drilling campaign. It is demonstrated that reliable estimates of the motions of most interest for a drilling operation can generally be obtained, thus providing support to the use of the provided numerical approach for conducting operability assessments for floating facility planning purposes.