A long history of wet gas pipelines in Victoria

2015 ◽  
Vol 55 (2) ◽  
pp. 415
Author(s):  
Steve Henzell
Keyword(s):  
Oil And Gas ◽  
Gas Pipelines ◽  
Gas Field ◽  
Initial Development ◽  
The North ◽  
Wet Gas ◽  
Industry Practice ◽  
Offshore Oil And Gas ◽  
The 1960S ◽  
Marginal Field

Australia's relative isolation and the harsh environment in Bass Strait have led to many innovations in offshore oil and gas developments. The initial developers were moving into frontier territory when Bass Strait was developed, with the harsh sea state and the water depths presenting major challenges. The original development of Bass Strait in the 1960s was tied to a wet gas pipeline philosophy, which was a novel step-out from normal industry practice. For example, the North Sea developments, which started shortly after Bass Strait, adopted dry gas export pipelines and required substantially larger platforms to process the gas for export. The cold waters of Bass Strait require an active hydrate management strategy and the success of hydrate inhibitors has been a key element in using wet gas pipelines. The initial development relied on methanol for hydrate inhibition, but this changed to a glycol-based hydrate inhibitor within 10 years of production start-up, due to challenges in the onshore production facilities. The use of mono-ethylene glycol for management of wet gas pipelines was demonstrated in Bass Strait. The success of the initial developments has given operators the confidence to pursue marginal field developments that rely on wet gas transport to the beach. The Minerva, Casino, Thylacine and Longtom gas field developments in Bass Strait have all adopted the same strategy, in part because of the confidence provided from operating the initial developments for many years.

Prospects for Sub Sea Wet Gas Compression

2008 ◽  
Author(s):  
Lars Brenne ◽  
Tor Bjo̸rge ◽  
Lars E. Bakken ◽  
O̸yvind Hundseid
Keyword(s):  
Oil And Gas ◽  
Development Program ◽  
Oil And Gas Industry ◽  
Full Scale ◽  
Gas Field ◽  
Gas Industry ◽  
The North ◽  
Wet Gas ◽  
Gas Compression ◽  
Petroleum Sector

Wet gas compression technology renders possible new opportunities for future gas/condensate fields by means of sub sea boosting and increased recovery for fields in tail-end production. In the paper arguments for the wet gas compression concept are given. At present no commercial wet gas compressor for the petroleum sector is available. StatoilHydro projects are currently investigating the wet gas compressors suitability to be used and integrated in gas field production. The centrifugal compressor is known as a robust concept and the use is dominant in the oil and gas industry. It has therefore been of specific interest to evaluate its capability of handling wet hydrocarbon fluids. Statoil initiated a wet gas test of a 2.8 MW single-stage compressor in 2003. A full load and pressure test was performed using a mixture of hydrocarbon gas and condensate or water. Results from these tests are presented. A reduction in compressor performance is evident as fluid liquid content is increased. The introduction of wet gas and the use of sub sea solutions make more stringent demands for the compressor corrosion and erosion tolerance. The mechanical stress of the impeller increases when handling wet gas fluids due to an increased mass flow rate. Testing of different impeller materials and coatings has been an important part of the Statoil wet gas compressor development program. Testing of full scale (6–8 MW) sub sea integrated motor-compressors (dry gas centrifugal machines) will begin in 2008. Program sponsor is the A˚sgard Licence in the North Sea and the testing takes place at K-lab, Norway. Shallow water testing of a full scale sub sea compressor station (12.5 MW) will begin in 2010 (2 years testing planned). Program sponsor is the Ormen Lange Licence.

JOHN BROOKES GAS FIELD DEVELOPMENT

2005 ◽  
Vol 45 (1) ◽  
pp. 13
Author(s):  
A.J. McDiarmid ◽  
P.T. Bingaman ◽  
S.T. Bingham ◽  
B. Kirk-Burnnand ◽  
D.P. Gilbert ◽  
...  
Keyword(s):  
Low Cost ◽  
Time Frame ◽  
Gas Production ◽  
Gas Field ◽  
Initial Development ◽  
North West ◽  
Field Development ◽  
The North ◽  
Production Wells ◽  
Development Approach

The John Brookes gas field was discovered by the drilling of John Brookes–1 in October 1998 and appraisal drilling was completed in 2003. The field is located about 40 km northwest of Barrow Island on the North West Shelf, offshore West Australia. The John Brookes structure is a large (>90 km2) anticline with >100 m closure mapped at the base of the regional seal. Recoverable sales gas in the John Brookes reservoir is about 1 Tcf.Joint venture approval to fast track the development was gained in January 2004 with a target of first gas production in June 2005. The short development time frame required parallel workflows and use of a flexible/low cost development approach proven by Apache in the area.The John Brookes development is sized for off-take rates up to 240 TJ/d of sales gas with the development costing A$229 million. The initial development will consist of three production wells tied into an unmanned, minimal facility wellhead platform. The platform will be connected to the existing East Spar gas processing facilities on Varanus Island by an 18-inch multi-phase trunkline. Increasing the output of the existing East Spar facility and installation of a new gas sweetening facility are required. From Varanus Island, the gas will be exported to the mainland by existing sales gas pipelines. Condensate will be exported from Varanus Island by tanker.

Advances in marine electromagnetic (EM) efficiency with a towed acquisition system

2012 ◽  
Vol 52 (2) ◽  
pp. 699
Author(s):  
Folke Engelmark ◽  
Johan Mattsson ◽  
John Linfoot
Keyword(s):  
Oil And Gas ◽  
Field Tests ◽  
Repeated Sequence ◽  
Dipole Source ◽  
Surface Sampling ◽  
Gas Field ◽  
The North ◽  
Simultaneous Acquisition ◽  
Oil And Gas Field ◽  
Source Signal

A towed marine EM system has been developing since 2004 where both source and receivers are towed behind the same vessel in an arrangement similar to 2D streamer seismic. This is an ideal technology for reducing risk in hydrocarbon targets in general and low saturation gas in particular, as well as the monitoring of CO2 sequestration. The dipole source is 400 or 800 m long and towed at 10 m below the sea surface. The receiver cable is towed at 100 m depth and has receiver offsets between 500 and 8,000 m. A transient source signal is used, allowing deterministic deconvolution of the source signature, which can be of any shape; for example, square wave, PRBS, or optimised repeated sequence (ORS). There are multiple benefits of the towed EM system: Similar in operation to a marine streamer seismic. Improved survey efficiency with source and receivers towed by the same vessel. Real-time monitoring of source and receivers, and quality control of incoming data. Onboard pre-processing. Dense sub-surface sampling. Receivers towed above the seafloor—the influence of strong local anomalies at the seabed is thus minimised. Facilitates simultaneous acquisition of EM and 2D seismic. Successful field tests were conducted in mid-2010 over the Peon gas field and the Troll oil and gas field in the Norwegian sector of the North Sea. A total of 615 line km were acquired during 138 hours, and the data has been successfully processed and inverted to delineate all targets.

Corrosion Fatigue of Welded Stainless Steels for Deepwater Riser Applications

2005 ◽  
Author(s):  
P. Woollin ◽  
S. J. Maddox ◽  
D. J. Baxter
Keyword(s):  
Corrosion Fatigue ◽  
Oil And Gas ◽  
Current Knowledge ◽  
Fatigue Loading ◽  
Fatigue Behaviour ◽  
Gas Field ◽  
Internal Surfaces ◽  
Oil And Gas Field ◽  
Offshore Oil And Gas ◽  
Offshore Oil

Steel risers for deepwater offshore oil and gas field developments are subject to seawater on the external surfaces, produced fluids on the internal surfaces and to fatigue loading. This paper reviews current knowledge of the corrosion fatigue behaviour of welded stainless steel for risers and presents results of testing of supermartensitic, duplex and superduplex grades in relevant environments.

Flow Assurance of Wet Gas Pipelines From a Corrosion Viewpoint

2002 ◽  
Author(s):  
Rolf Nyborg ◽  
Arne Dugstad
Keyword(s):  
Carbon Steel ◽  
Oil And Gas ◽  
Prediction Models ◽  
Process Equipment ◽  
Corrosion Control ◽  
Internal Corrosion ◽  
Application Range ◽  
Wet Gas ◽  
Offshore Oil And Gas ◽  
Stabilization Technique

In many offshore oil and gas projects under development, the pipeline costs are a considerable part of the investment and can become prohibitively high if the corrosivity of the fluid necessitates the use of corrosion resistant alloys instead of carbon steel. Development of more robust and reliable methods for internal corrosion control can increase the application range of carbon steel and therefore have a large economic impact. Corrosion control of carbon steel pipelines has traditionally often been managed by the use of corrosion inhibitors. The pH stabilization technique has been successfully used for corrosion control of several large wet gas condensate pipelines in the last few years. Precipitation of scale and salts in the pipeline and process equipment creates further challenges when formation water is produced. Different corrosion prediction models are used in the industry to assess the corrosivity of the transported fluid. An overview of the present models is given together with a link to fluid flow modeling.

Long Pile Upending Lifting Study for Fixed Platform on Offshore Oil and Gas Field

2014 ◽  
Author(s):  
Yandong Zhou ◽  
Facheng Wang
Keyword(s):  
Deep Water ◽  
Oil And Gas ◽  
Cost Effective ◽  
Analysis Model ◽  
Gas Reservoirs ◽  
Gas Field ◽  
Water Developments ◽  
Oil And Gas Field ◽  
Offshore Oil And Gas ◽  
Offshore Oil

Fixed platform have been widely employed in the offshore oil and gas reservoirs development. Pile foundation reliability is critical for these platforms where drilling, production and other functions are integrated. The lifting operation for the long pile, being a key step in the jacket installation, has been considered for further developments. With deep water developments, the sizes and weights of long piles are reasonably bigger. The corresponding process and equipment employed are subsequently altered, which brings challenges to developing a cost-effective, easy-operable approach for lifting operation. In this paper, the technology for the offshore long pile upending lifting operation including pile feature, installation methodology, lifting rigging and analysis model, covering water depths ranging from shallow to near deep water zone (60–300 m water depth) has been suggested. In addition, the applicability of the adoptable novel approaches has been discussed considering the practical project experience.

Optimization of OSV Fleet for an Offshore Oil and Gas Field in the Russian Arctic

2015 ◽  
Author(s):  
Aleksandar-Saša Milaković ◽  
Mads Ulstein ◽  
Alexei Bambulyak ◽  
Sören Ehlers
Keyword(s):  
Supply Chain ◽  
Environmental Conditions ◽  
Oil And Gas ◽  
The Arctic ◽  
Russian Arctic ◽  
Gas Field ◽  
Arctic Conditions ◽  
Oil And Gas Field ◽  
Offshore Oil And Gas ◽  
Offshore Oil

Due to a constantly increasing global energy demand on one side, and depletion of available hydrocarbon resources on another, a continuous search for new reserves of hydrocarbons is required (BP Energy Outlook 2035 [1]). Having in mind that estimated 22% of the world’s undiscovered petroleum is located in the Arctic, 84% of which is projected to be offshore (US Geology Survey [2]), the Arctic becomes a logical region of activities expansion for the oil and gas industry. Opposing large expected quantities of hydrocarbons that are to be found in the Arctic, there are also numerous challenges that need to be overcome in order to make production economically feasible. One of the segments of offshore production process that is expected to be influenced by Arctic conditions is upstream supply chain, or chain of delivery of products and services that are necessary for unhindered operation of an offshore field. Within upstream supply chain, it is expected that the configuration of Offshore Supply Vessel (OSV) fleet will be significantly affected by specific Arctic conditions, mainly by large distances to supply base as well as by environmental conditions. Therefore, this paper seeks to identify an optimal composition of OSV fleet taking into consideration specific Arctic conditions. A simulation model describes an upstream supply chain taking into consideration stochastic nature of environmental conditions in the Arctic. An optimization model is built on top of the simulation model in order to assess optimal configuration of the fleet with respect to operational costs. Simulation and optimization are run for a case of an offshore oil and gas field development in the Russian Arctic.

Corrosion Fatigue of Welded C-Mn Steel Risers for Deepwater Applications: A State of the Art Review

2005 ◽  
Author(s):  
S. J. Maddox ◽  
R. J. Pargeter ◽  
P. Woollin
Keyword(s):  
Oil And Gas ◽  
Current Knowledge ◽  
Fatigue Loading ◽  
Fatigue Behaviour ◽  
Manganese Steel ◽  
Gas Field ◽  
Internal Surfaces ◽  
Oil And Gas Field ◽  
Offshore Oil And Gas ◽  
Girth Welds

Steel risers for deepwater offshore oil and gas field developments are subject to seawater on the external surfaces, produced fluids on the internal surfaces and to fatigue loading. This paper reviews current knowledge of the fatigue behaviour of welded carbon-manganese steel for risers in relevant environments. A substantial body of data exists relating to the performance of girth welds in seawater with cathodic protection and consequently recent attention has been turned to establishing the fatigue performance in the internal environment, which may contain water, CO2, H2S and chloride and bicarbonate ions.

Sign in / Sign up

Export Citation Format

Share Document