Offshore deepwater discoveries have driven the development of new compactseparation technologies, a core aspect of subsea processing. Compact separatorsare much smaller than conventional separators and have the potential tosignificantly reduce capital expenditure for deepwater developments. Unfortunately, reducing the size of separators generally reduce the separationperformance and the robustness to handle fluctuations in flow rate andcomposition. It is therefore essential to find an acceptable balance betweenthe realized reduction in overall capital expenditure and reduced tolerance tofluctuating conditions. To maximize the economics of a subsea development, itis important to understand how the technology selection impacts performance, risks, costs, and ultimately the attractiveness of deepwater subsea processing. Proactive technology screening and qualification are required. This paperpresents one of several ongoing joint industry projects to develop and screenseparation technologies for deepwater applications, the DEMO 2000 project: NextGeneration Deepwater Subsea Gas-liquid Separation System. An overview ofavailable technologies for separation in deep water is disclosed, includingcyclonic separators, compact gravity-type separators, and slug dampeningtechnologies. Their characteristics, typical performance and maturity level arediscussed. Finally, the program activities are explained and some highlightsfrom the separation test program are shared. Introduction Value Drivers for Subsea Gas-liquid Separation In recent years, subsea processing, and more specifically subsea separation, has been recognized as one of the most promising technology developments in theoffshore industry. With the recent success at Perdido [Ju et al., 2010], Parquedas Conchas (BC-10) [Iyer et al., 2010; Deuel et al., 2011], and Pazflor[Eriksen, 2012], subsea separation is attracting interest from industry becauseof its ability to increase production, enhance recovery, and improve fieldeconomics on a commercial scale. Subsea separation is, in general, stillconsidered an emerging technology area; therefore the benefits and capabilitiesmust be clearly demonstrated to infuse acceptance and confidence as thepreferred development option. McClimans and Fantoft [2006] and Di Silvestro etal. [2011] have presented a detailed review of the value drivers for subseagas-liquid separation, which is the topic of this paper. In summary, subseagas-liquid separation has proven to provide strong business incentives withenabling capabilities, including (i) more efficient liquid boosting, (ii)longer range gas compression from subsea to onshore, (iii) cost efficienthydrate management, (iv) effective riser slug depression, (v) and access tochallenging field developments that otherwise would be abandoned or notdeveloped (due to their remote location, harsh conditions, longer tie-backrequirements, or low reservoir drive). The main drivers are discussedbelow.

Production from North Rankin A platform (NRA) aims to meet the objective of supplying contract gas/LNG whilst maximising the condensate yield. This paper describes current efforts to increase production of selected wells through an extension of tubing flow velocity limits. By doing so, condensate rich wells can be produced preferentially at higher rates and overall flexibility between wells with regards to maintaining contractual gas production can be improved. Arguments used to define a new limit to tubing flow velocity are presented together with the agreed basis for allowable sand production. Also discussed are the monitoring practices undertaken to ensure a long term field trial is completed safely. Here, particular emphasis was placed on proving the reliability of sand monitoring by performing field comparison trials of available systems prior to the commencement of the high rate trial.

Smiety of Petroleum Engineers. Ekctronb reprcduciion, distrtsition, or storsge of sny part of this paper for cwrnmem"sl PUPS without the kwitten mnsent of the Sceiety of Petroleum Engineets is prohibtied. Permission to reproduce in print is restricted to an abatrsct cf not more than WI words iluatrations may not be wpiad. The abstrsct must contdn conspicuous scknowfedgment of where and by whcm the paper ws presmtad. Wtite Librarian, SPE, P.O. Box 833835, Richardson, TX 75083-3336, U.S.A., fsx 01-972-952-9435. AbstractGoodwyn platform wells produce up to 220MMscf7d of raw gas yiel~ng UP to 20,000 bpd of stabilised condensate. The high productivity of the wells has reduced the number of development wells needed to satistJ platform capacity with significant cost savings. This high well capacity was achieved through the early recognition of the reservoir inflow potential in the completion design and addressing the critical issues of erosional velocity, Iifecycle sand production, sub-surface and surface equipment integrity in a high flow, high stress environment. To maximise the well potential the erosional limit was extended based upon actual experience. The risk of sand production was managed through a philosophy covering sand prediction and its control during operation. Well hardware was tightly specified and qualified within the defined operating envelope. These solutions were applied to both the initial conventional wells and for the later extended reach horizontal wells. Results fkom Goodwyn wells demonstrate that actual performance match the targeted ideal and that the issues have been managed. This paper presents a systems approach to well design where technical and external issues are taken into consideration. It is a retrospective look at the issues addressed for Goodwyn well desi~with updates to include current techniques.

Offshore rig rates are at an all time high and wells are becoming bigger and longer, in deeper waters and in more complex reservoirs. Well testing in this environment has become more challenging, where well clean-up and flow assurance issues such as slugging and hydrates can significantly extend the planned duration of well tests. The ability to predict and being prepared to deal with such problems by appropriate design of well test equipment can reduce operational risk, minimise safety hazards and environmental impact and potentially save millions of dollars in rig-time. Traditional well flow software only models steady-state flow. Predicting the transient behaviour of wells, from the unloading of completion fluids until steady state flow conditions are reached, requires specialised software. Dynamic flow simulation software is a proven tool which has been applied for years by facilities engineers for pipeline and slug-catcher design, but its application for well testing is a new practice. Key outputs from dynamic well simulation include slug sizes and frequency, fluid composition and pressure-temperature trends at any time and at any point in the well. Such information enables optimum design so all parameters are within the equipment's allowable operating envelope at any time of the well test operation. This paper describes how dynamic simulation, using the software package OLGA, was applied to a big-bore gas well with 9 5/8″ production tubing. The dynamic simulation study:provided better understanding of well unloading behaviour at different flowrates (by using different choke sizes).assessed the effect of an emergency shut-down (ESD) during a well clean-up operation.defined the minimum flowrate required to cleanup the well (for sizing well testing equipment). Results from the dynamic simulation indicated that a standard well test package may be adequate for cleaning up this big-bore gas well with 9 5/8″ production tubing, though the equipment would be operated at or near its limits and would take quite some time for clean-up. A significantly faster clean-up could be achieved with a high rate well test package at additional cost. Case Study The Thylacine and Geographe gas fields are located in the Otway basin, 70 km and 55km from the Victorian coast in South-eastern Australia - Fig.1. Discovered in 2001, gas from these two fields is expected to supply a total of 950 billion cubic feet of raw gas into the domestic market (equivalent to 885 petajoules of sales gas, 12.2 million barrels of condensate and 1.7 million tonnes of LPG). The first phase of the development will tap into the Thylacine field with four wells from an unmanned platform in 100 m of water. Gas will be sent via a 20″ pipeline to a newly built processing plant near Port Campbell - Fig.2. The Geographe field, located 15km north of Thylacine, will be connected by subsea pipelines to the main pipeline in a later development phase. The joint venture partners in this development are:Woodside Energy Ltd (Operator) 51.55%Origin Energy Resources 30.75%Benaris International NV 12.7%CalEnergy Gas Australia 5.0% Well description TM-1 is a big-bore well with a 9 5/8″ production tubing - Fig.3. The well is vertical until ∼650 m, where it kicks off at a tangent, intersecting the reservoir at a 31o angle. Well depth is about 2600 m measured depth (mMD) or 2300 m true vertical depth (mTVD). Reservoir temperature is ∼120oC. Models Description The TM-1 well model used to run the simulations was built using the multiphase flow simulator OLGA. The key model building considerations are well geometries, wall materials and layers, fluid PVT and boundary conditions (reservoir pressure and wellhead backpressure). Clean-up simulations were started from the initial underbalanced conditions using different choke sizes. The well models were allowed to run until the brine, diesel and mud had been displaced from the well and steady state conditions were reached. Mud was included in the model to assess the effect of backproducing mud lost into the formation during drilling. Details are described in the following sections.

TX 75083-3836, U.S.A., fax 01-972-952-9435. AbstractOffshore rig rates are at an all time high and wells are becoming bigger and longer, in deeper waters and in more complex reservoirs. Well testing in this environment has become more challenging, where well clean-up and flow assurance issues such as slugging and hydrates can significantly extend the planned duration of well tests. The ability to predict and being prepared to deal with such problems by appropriate design of well test equipment can reduce operational risk, minimise safety hazards and environmental impact and potentially save millions of dollars in rig-time.Traditional well flow software only models steady-state flow. Predicting the transient behaviour of wells, from the unloading of completion fluids until steady state flow conditions are reached, requires specialised software. Dynamic flow simulation software is a proven tool which has been applied for years by facilities engineers for pipeline and slugcatcher design, but its application for well testing is a new practice. Key outputs from dynamic well simulation include slug sizes and frequency, fluid composition and pressuretemperature trends at any time and at any point in the well. Such information enables optimum design so all parameters are within the equipment's allowable operating envelope at any time of the well test operation. This paper describes how dynamic simulation, using the software package OLGA, was applied to a big-bore gas well with 9 5/8" production tubing. The dynamic simulation study: 1. provided better understanding of well unloading behaviour at different flowrates (by using different choke sizes). 2. assessed the effect of an emergency shut-down (ESD) during a well clean-up operation. 3. defined the minimum flowrate required to cleanup the well (for sizing well testing equipment).Results from the dynamic simulation indicated that a standard well test package may be adequate for cleaning up this big-bore gas well with 9 5/8" production tubing, though the equipment would be operated at or near its limits and would take quite some time for clean-up. A significantly faster clean-up could be achieved with a high rate well test package at additional cost. Case StudyThe Thylacine and Geographe gas fields are located in the Otway basin, 70 km and 55km from the Victorian coast in South-eastern Australia - Fig.1. Discovered in 2001, gas from these two fields is expected to supply a total of 950 billion cubic feet of raw gas into the domestic market (equivalent to 885 petajoules of sales gas, 12.2 million barrels of condensate and 1.7 million tonnes of LPG).The first phase of the development will tap into the Thylacine field with four wells from an unmanned platform in 100 m of water. Gas will be sent via a 20" pipeline to a newly built processing plant near Port Campbell - Fig.2. The Geographe field, located 15km north of Thylacine, will be connected by subsea pipelines to the main pipeline in a later development phase.