BP's largest subsea development, PSVM, sits in water depths of 2,000 metres located north-west of Luanda in block 31. It's the first ultra-deepwater development in the continent of Africa and the most expansive sub-sea development in the industry to date due to the combination of water depth and geographical spread. From the initial discoveries in 2002 to 2004, and as early project planning took shape in late 2005, it was realised the scale of the development, water depth, and location would present new challenges to the industry and BP. Given the reservoir quality, sand distribution, and highly unconsolidated formations, all zones of interest in the development require sand control completions. Because of the ultra-deep water depth and subsea infrastructure, intervention operations and costs are prohibitive; thus, completions are designed to minimize the need for interventions during the life of the well. This objective has driven the need for robust equipment design with respect to longevity, corrosion, erosion-resistant, and remote monitoring and control. The production wells were completed as open hole gravel packs, resulting in technical limit productivity along with exceptional mechanical reliability and integrity. All wells completed to date have shown zero formation damage, contributing to the planned field plateau production output of 150 Mbpd. To sustain this production capability, voidage replacement is important and therefore, the injection wells are mandated to deliver equivalent well performance through the use of effective sand-control completion designs. Based on this, cased hole frac-pack completions were selected for the initial gas injection wells and stand-alone screen completions for the water injectors. The injectors have set the bar for flow efficiency in high transmissibility reservoirs and are some of the largest injector completions in BP's portfolio. This paper discusses the keys to the successful delivery and well productivity of the first 7 out of 40 wells of this world class ultra-deep subsea development. It reviews the PSVM completion basis of design as well as incorporates completion best practices and lessons inherited from BP Angola's first deepwater project, Greater Plutonio and Angola Joint Venture operations (White et al, 2008).
Barite sag or solids sag is a phenomenon where by a fluid sheared at low flowrate does not have the viscous properties necessary to keep the solids within it in suspension. The solids can subsequently fall out of suspension, which can lead to an undesireable build-up of solids in the wellbore or density contrasts within the fluid. During drilling activities solids sag can be avoided by increasing flow rates, rotating the drill pipe, and viscosifying the drilling mud. However, during completions operations, none of these mitigating practices may be possible due to limitations of the setting tools or installed equipment deployed into the well. For open hole completions where sand screens are deployed in highly conditioned muds, solids sag has the potential to be a serious issue, and needs to be avoided. Since 2009, there have been at least four incidents of solids sag occurring during completions operations in the Greater Plutonio development in deepwater Angola, at relatively low fluid densities. Each event manifested itself in a different way, and caused different problems during and after installation of the completion equipment. This paper presents case studies of the solids sag events that occurred during completions operations, and how they either affected installation operations or well productivity. It then describes the work done to eliminate the solids sag, including fluids testing performed to identify it, changes to operational practices, short term modifications to mud rheology, and long term mud solutions.
Angola is home to two of BP's largest subsea developments, Greater Plutonio and PSVM. High rate production wells have been achieved through the use of long open hole gravel pack completions, with alternate path screen design. Since the screens are deployed in conditioned oil based mud, the open hole is displaced to aqueous fluid prior to gravel packing the well. The early Greater Plutonio wells extensively utilised what is referred to as the 'conventional,' 'forward,' or Heel-to-Toe technique to displace the oil based fluid to water based. However, depletion of some of the reservoir sands increased the likelihood of screen plugging in wells with long open hole sections, as demonstrated by a handful of incidents. Also, the tight pore pressure to fracture gradient (PPFG) windows and small screen gauge sizes in the PSVM development made the 'forward' technique less suitable to adopt as a basis of design. As such, both projects developed a different displacement technique referred to as 'reverse' or Toe-to-Heel circulation to overcome the issues of sand control screen plugging and small PPFG windows. Work was performed to confirm that service tools could maintain full functionality, the fluid pill train properties were appropriate, and that hydraulic models could adequately predict the ECDs generated during the displacement. Eight open hole gravel pack wells, across both projects, have now been successfully completed using the Toe-to-Heel technique. Using the data from these wells, along with the existing data set from the earlier Greater Plutonio wells, it has been possible to determine a set of guidelines which indicate which technique is best suited under certain conditions. This paper briefly describes the history of the two projects, details the operational differences between both methods, describes the evolution of the modelling work done for ECD prediction, including several pros and cons associated with each method. The actual displacement data is also presented, and is compared with the predictions from the initial modelling simulations. The development of even more accurate modelling techniques is also discussed.
Greater Plutonio is a 5 field subsea, deepwater project, located offshore Angola. Development began in 2005 and 38 wells have now been completed in highly permeable but poorly consolidated Oligocene reservoirs. Production commenced in October 2007 and is supported by injection of over 350mbd of water into 21 water injectors, predominantly completed with Stand Alone Screens. As the fields have multiple stacked reservoirs, dual zone downhole flow control (DHFC) is advantageous in many water injectors as it allows better control of injection conformance and / or a reduction in well count. During the design phase, it was recognized that although much of the hardware for DHFC systems for water injectors was field proven, the ability to create a long term seal between zones with openhole completions, especially in the deepwater environment, was a significant challenge that had not yet been addressed by the industry. The key challenges were: High differential pressure rating (3000psi). Achieve a robust seal in non-circular wellbores. Large axial load resulting from temperature reduction and differential pressure (>400,000lbs). Large number of injection and shut-in cycles occur over life of well. Large changes in temperature and consequently axial loading occur with each cycle. Following a technical evaluation, a novel dual cup packer concept with integral sliding movement joint and openhole packer slips was selected. This was followed by a 2.5 year rigorous design and qualification period prior to field installation1. 8 DHFC water injection wells have now been installed in Greater Plutonio, and downhole pressure data shows that the cup packers are providing robust high pressure seals after 3.5 years of high rate water injection. The cup packer system has produced a step change in openhole packer technology that has facilitated installation of reliable DHFC water injection wells at scale in the deepwater environment.
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