Layer | Fill | Outline |
---|
Map layers
Theme | Visible | Selectable | Appearance | Zoom Range (now: 0) |
---|
Fill | Stroke |
---|---|
Collaborating Authors
This article, written by Editorial Manager Adam Wilson, contains highlights of paper SPE 154452, ’Challenges in Sour-Gas Handling for Kuwait Jurassic Sour Gas,’ by Bader Nasser Al Qaoud, SPE, Kuwait Oil Company, prepared for the 2012 SPE Middle East Unconventional Gas Conference and Exhibition, Abu Dhabi, 23-25 January. The paper has not been peer reviewed. Kuwait Oil Company started free gas production from its Jurassic sour-gas field in May 2008 with the commissioning of Early Production Facility (EPF) 50. The field produces sour gas and light crude from a deep high-pressure/high-temperature naturally fractured carbonate reservoir with low permeability and low porosity. The well fluid is characterized by high hydrogen sulfide (H2S) (5%) and carbon dioxide (CO2) (5%) content. Handling such highly corrosive well fluid creates a wide range of challenges, from upstream at the wellhead to downstream at the processing facility. Upstream Challenges Upstream challenges for the Jurassic gas field have been related mostly to subsurface corrosion of tubing, unplanned well downtime because of hydrate formation during winter, and failure of automated chokes for some wells. Subsurface Tubing Corrosion. A moderate to severe corrosion rate has been indicated by corrosion logs in the production tubing because of the high H2S and CO2 content of the well fluid. Plans exist for existing carbon-steel tubing for four wells to be replaced by corrosion-resistant alloy material, and regular corrosion logs are being run for other suspect wells. Hydrate Formation in Flowlines. Hydrate formation has been observed in flowlines during winter for 11 wells when flowline temperature drops to 65°F. This has resulted in unplanned production loss and substantial well downtime. The best mitigation option implemented was the injection of kinetic hydrate inhibitor (KHI) at the wellhead at the onset of winter for the identified wells, and a good degree of success has been achieved. However, KHI is not very effective in controlling hydrates at temperatures below 4°C, and this is a problem that needs to be addressed as a priority. Flowline insulation at the point of restriction and heat tracing also have been implemented for four wells, with a fair amount of success. Challenges With Automated Chokes. Automated chokes were first installed in the field in April 2011. The purpose of automation was to improve control of remotely located wells, enhance safety, and ensure better control of field production. Sixteen Jurassic wells are currently on automated chokes of three different makes—M1, M2, and M3. Challenges With Make M1. The factory-set choke opening did not match actual choke opening. Choke adjustments had to be made with flowing wellhead pressure (FWHP) as a reference, and this leads to inaccurate settings. Scale formation also has been observed in-side the choke body, causing restricted flow and inaccurate FWHP readings and, therefore, poor monitoring of well performance.
- Asia > Middle East > UAE > Abu Dhabi Emirate > Abu Dhabi (0.25)
- Asia > Middle East > Kuwait > Jahra Governorate (0.25)
- Energy > Oil & Gas > Upstream (1.00)
- Materials > Chemicals > Commodity Chemicals > Petrochemicals (0.34)
- Asia > Middle East > Kuwait > Jahra Governorate > Arabian Basin > Widyan Basin > North Kuwait Jurassic (NKJ) Fields > Marrat Formation > Upper Marrat Formation (0.99)
- Asia > Middle East > Kuwait > Jahra Governorate > Arabian Basin > Widyan Basin > North Kuwait Jurassic (NKJ) Fields > Marrat Formation > Sargelu Formation (0.99)
- Reservoir Description and Dynamics > Unconventional and Complex Reservoirs (1.00)
- Production and Well Operations > Production Chemistry, Metallurgy and Biology > Corrosion inhibition and management (including H2S and CO2) (1.00)
- Health, Safety, Environment & Sustainability > Health > Noise, chemicals, and other workplace hazards (1.00)
- Facilities Design, Construction and Operation (1.00)
Abstract The Balmoral Floating Production Vessel (FPV) has been on location in block 16/21 of the UKCS since August 1986. The Vessel has produced virtually continuously in some of the worst weather experienced in the North Sea for several years. This paper presents the first 3 years of the operational 1ife of the Balmoral FPV. It describes the major plant items and how they have behaved in service. Weather sensitivity is discussed along with modifications which have been made. Introduction The Balmoral FPV was built in Sweden and arrived on location in August 1986. First oil came in late November of the same year and the rate gradually built up to plateau as wells were brought online. Figure 1 shows the production profile since startup. A description of the vessel, along with design criteria has been presented previously. Briefly, the floating vesse1 acts as the production faci1ity to separate the gas, water and oil from 13 template and satellite wells. It is connected to the sub sea template by flexible risers. The facility also has the necessary equipment to perform work overs, drilling, water injection and gas lift. Down hole/Gravel Pack/Sub sea The Balmoral Field has been developed using 10 template and 3 satellite production wells and 6 satellite water injection wells - see Figure 2 for field location map. All the wells were comp1eted prior to the arriva1 of the FPV on location and startup of production. In addition, 2 further fields have been developed using the Balmoral FPV facilities: the Glamis field which consists of 2 satellite production wells and one satellite water injection well and the Blair field which consists of one satellite production we11. Production from these fields commenced in the summer of 1989. Initially all of the Balmoral wells were gravel packed for the purposes of sand control. However during the completion of a satellite production well, the gravel pack resulted in such a significant reduction in productivity that the well was unable to meet its production target. As a result the gravel pack was pulled and the well recompleted without a gravel pack. In addition, there have been 2 gravel pack failures to date. These were due to chloride stress corrosion cracking of the wire wrapped screens induced by stimulations of the wells with HCl and HCl/HF acids. Subsequent to this new stimulation treatments have been designed based on acetic and HF acids. Sand production from the wells is being monitored by the use of sand probes on the FPV although they have not proven to be very successful. At present the sand production rates are such that it does not constitute an operational problem. However should such a problem arise then serious consideration will be given to regravel packing these wells.
- Europe > United Kingdom > North Sea > Central North Sea > Moray Firth (0.88)
- North America > United States > Texas (0.88)
- Energy > Oil & Gas > Upstream (1.00)
- Water & Waste Management > Water Management > Lifecycle > Disposal/Injection (0.78)
- Europe > United Kingdom > North Sea > Central North Sea > Moray Firth > Moray Firth Basin > Witch Ground Graben > Block 16/21a > Glamis Field (0.99)
- Europe > United Kingdom > North Sea > Central North Sea > Moray Firth > Moray Firth Basin > Fladen Ground Spur > Block 16/21c > Balmoral Field > Lista Formation (0.97)
- Europe > United Kingdom > North Sea > Central North Sea > Moray Firth > Moray Firth Basin > Fladen Ground Spur > Block 16/21c > Balmoral Field > Andrew Formation (0.97)
- (4 more...)
Abstract Sand production in the brown field is a common phenomenon. If left uncontrolled, sand can erode the line pipes, valves, instrumentsand ultimately causes unplanned production shutdown. Even if the sand production rate is relatively low, sand can accumulate inside the production separators after a period of production. This sand build-up is reducing vessel volume for effective separation of oil, gas and water. Dulang-B Platform, which is located at South China Sea and operated by Petronas Carigali Sdn Bhd (PCSB), has recorded severe sand accumulation on its production separators as observed during vessel inspection. This resulted in unnecessary production downtime to allow for cleaning of the vessel and removal of sand. To mitigate the problem, two units ofOnline Vessel Desander (OVD) manifolds were installed inside one of theHP Production Separator of the platform on trial basis. Each manifold consists of a series of pipe work connected to the desander devices. The device uses hydrocyclone principle to elevate and transport sand from the base of the vessel out to a filter tank without the need to isolate the process stream. This pilot installation of the manifolds was the first in PCSB and Malaysia. Over a month period, a total of 809 litres of sand have been removed from the separator vessel with no production downtime. Operations personnel reported improvements on level interface of the separator and less erosion on the downstream equipment, particularly level control valves. The annual shutdown previously required for sand cleaning was also eliminated resulting in monetary savings. Thus, the OVD manifolds are an effective technology to replace conventional sand jetting for sand removal from production separators. Introduction Dulang Field was experiencing severe sand production from the reservoir as indicated by well test data and as observed from sand accumulation level in the production separators during planned shutdown. Sand accumulation over six months has reached a level of up to 40% vessel height. The separator vessels were originally equipped with conventional sand jetting facilities, which fluidize the sand to be disposed along with the produced water at the three-phase separator water outlet. The problems with this sand jet system is that the jet nozzles are easily damaged, the water outlet get clogged and the sand were carried over into the produced water line which eroded the level control valve and clogged the downstream coalescer plates for oily water separation vessel. Based on recommendations from the feasibility study, OVD manifolds were proposed to be installed in V-504 HP Separator as a pilot project. The manifolds were then installed and initially commissioned on 28July 2004 during Dulang Field planned shutdown in a simulated environment. Actual performance commissioning took place on 15 September 2004, when the production sand had a sufficient period of time to accumulate. The two units of OVD manifolds, namely Manifolds A & B, were installed inside V-504. The manifolds are designed to remove sand from the HP Separator while in operation i.e. no production downtime is required for sand removal. The OVD manifolds were installed and operated inside the HP Separator on trial basis for one month to evaluate its sand removal performance. At the end of the trial period, both manifolds removed about 809 litres of produced sand. Hence, the pilot project proved to be successful and was accepted for implementation. It is to be noted that modifications to the existing facilities were minimized during installation of the manifolds to reduce capital costs for the evaluation trial. The existing sand jet piping was reused to support the manifolds and no welding was involved during the installation.
- North America > United States > Texas (0.87)
- Asia > Malaysia > Terengganu > South China Sea (0.44)
Abstract The Captain Field in the UK North Sea is a shallow heavy crude reservoir, which has been successfully developed using ESP's, long reach horizontal wells and an FPSO installation. The Field has been in production since the early 1997 and has maintained a high uptime during this period. However, there have been some notable occasions when production has been interrupted. Uptime data is presented and the reasons for production losses and the improvements made are discussed. The competence of FPSO crews has been the subject of concern to Operators and the Regulatory Authorities in the North Sea, and the system developed for the Captain FPSO is illustrated. Since the commencement of production, there have been some significant safety, health and environmental challenges associated with the Captain FPSO. These have been the result of design as well as operational constraints. A comparison of the Captain SH&E data with the rest of the industry is presented. Introduction The Captain Field is a heavy oil (19 degrees API) development in the Outer Moray Firth area of the North Sea. The Field facilities consist of a wellhead protection platform (WPP 'A') and an FPSO. A schematic of the field facilities is shown in figure 1. The installation of the existing facilities was completed early first quarter of 1997 and production commenced on the 1 April 1997. An extension to the existing facilities is planned to be installed in mid 2000 to recover the reserves from the eastern part of the field (Area B) and will consist of a subsea template tied back to a platform bridgelinked to the WPP 'A'. Production from these additional facilities is planned to commence in the December 2000. The WPP 'A' is the drilling centre for the western part of the field (Area A) and well fluids are transferred to the FPSO for processing by a series of pipelines. All the wells have electrically powered submersible pumps and downhole chemical injection of demulsifier and corrosion inhibitor. A hydraulic submersible pump was installed on the WPP 'A' as part of the testing of equipment for Area B. The process system on the FPSO consists of a single two-stage separation train and an electrostatic coalescer. A schematic of the process is shown in figure 2. The process fluids are heated to approximately 90 degree's centigrade between the 1 and 2 stage separators. Pressure support to the reservoir is provided by water injection facilities located on the FPSO, excess water may be discharged overboard. The FPSO generates all the electrical power for the Field through five tri-fuel generator sets. The FPSO has an oil storage capacity of 550,000 bbls arranged in 3 sets of wing tanks and 2 centre tanks, and two slops tanks are available for the storage of liquids which are not of exportable quality. The vessel itself has all the normal equipment that is found on a tanker, eg. inert gas generator, ballasting systems etc.
- Europe > United Kingdom > North Sea > Central North Sea > Moray Firth (0.45)
- Europe > United Kingdom > Scotland > North Sea (0.24)
- Energy > Oil & Gas > Upstream (1.00)
- Water & Waste Management > Water Management > Lifecycle > Disposal/Injection (0.52)
Abstract For decades sucker rod pump artificially, lifted wells have used devices called pump off controllers (POC) to match the pumping unit's runtime to the available reservoir production by idling the well for a set time where variable frequency drives are not available. In doing this the POC allows the well to enter a set period of downtime when the downhole pump fillage is incomplete to avoid premature failures, and then brings the well back online to operate before production is lost. Although this method has been successful for several years, autonomous control algorithms can be utilized to reduce failures or increase production in cases where the downtime is not already optimized. Optimizing the idle time for a sucker rod pump artificially lifted well involves understanding the amount of time required to fill the near wellbore storage area before generating a fluid column above the pump intake that will begin to hinder inflow from the reservoir into the wellbore. By varying the idle time and observing the impact on production and cycles the program hunts for the optimal idle time. By constantly hunting for the optimal idle time the optimization process can adjust the idle time when operating conditions change. This gives the advantage of always meeting the current wellbore and reservoir conditions without human intervention. Autonomously modulating the idle time for a well, if done properly will reduce incomplete fillage pump strokes in cases where the idle time is too short or will increase the wells production in cases where the idle time is too long. Overall this will result in the optimization of wells by reducing failures and/or increasing production, generating a huge value to the end user by automating the entire process of downtime optimization.
- North America > United States > Texas > Permian Basin > Yeso Formation (0.89)
- North America > United States > Texas > Permian Basin > Yates Formation (0.89)
- North America > United States > Texas > Permian Basin > Wolfcamp Formation (0.89)
- (24 more...)