Many of the water injectors in sand control environments are being completed as long open holes due to higher injectivities attainable with such completions. Although target rates may often be achieved without any cleanup chemicals in production wells, injection wells require filtercake cleanup, in cases where • producing the well prior to injection is not feasible or desirable, (e.g., limited storage capacity on the rig, or artificial lift requirements due to low pressure or injection into water leg) • injecting above frac pressure is either not feasible (e.g., very high frac pressures and pump limitations) or not acceptable (e.g., sweep efficiency, premature water breakthrough, uncontrolled fracture height growth).Although a large variety of filtercake cleanup techniques and chemistries are available in the industry, most of these solutions are effective in producers. As demonstrated through laboratory experiments, achieving consistently high injectivities requires removal of drill solids from the filtercake, through either dissolution (e.g., acid formulations utilizing HF) or effective displacement techniques that will not result in injection of these solids into the formation pore throats (SPE 77449). In addition, an effective filtercake removal (including drill solids) in long open holes without inducing high losses into the formation (so that the wash pipe can be pulled out and a mechanical fluid loss control valve can be activated) remained as a formidable challenge, which becomes even a bigger challenge in wells drilled with conventional oil based muds (OBM), particularly in reactive shale environments.In this paper, we present a novel technique that addresses these challenges, proven through field application on a standalone screen water injector in Nigeria. The technique involves displacement of OBM from openhole with a viscous spacer pill containing a demulsifier, followed by completion brine containing a mutual solvent to weaken the filtercake without attacking the bridging agents, subsequently performing a high rate viscous pill displacement to remove the external cake, and finally spotting a water-based self-destructive fluid loss control pill to control the losses while pulling the wash pipe. Laboratory testing for designing the displacement stages, field execution, and well performance evaluation are detailed.
TX 75083-3836 U.S.A., fax 01-972-952-9435. AbstractThis paper outlines and discusses the issues surrounding the TOTAL AUSTRAL Carina and Aries field development project and the engineering issues addressed to facilitate achieving the project goals of producing gas at high rates from the shallow unconsolidated sand stone reservoirs. The main challenge in terms of completion architecture was to maximize the well head flowing pressure while insuring "long term integrity" of wells. This was addressed through implementation of limited -or even not -proven technologies.
This paper outlines and discusses the issues surrounding the TOTAL AUSTRAL Carina and Aries field development project and the engineering issues addressed to facilitate achieving the project goals of producing gas at high rates from the shallow unconsolidated sand stone reservoirs. The main challenge in terms of completion architecture was to maximize the well head flowing pressure while insuring "long term integrity" of wells. This was addressed through implementation of limited - or even not - proven technologies. Introduction TOTAL AUSTRAL operates the Carina and Aries fields, located in offshore Tierra del Fuego in the most southern region of Argentina (Figure 1). These fields are prolific gas fields and are being developed with a reduced number of wells, with departures of up to 4 Km @ 1500 m TVD/RKB. The drilling scenario for Carina/Aries phase 1 included two horizontal wells to be drilled from the platform CARINA-1 (85 m water depth) and two horizontal wells from the platform ARIES (65 m water depth) for a targeted production plateau of 12 MSm3/d of gas with 3 to 4 MSm3/d by well at relatively low pressure (80 bars WHFP). Maximizing the Wellhead Pressure The surface project includes the two platforms respectively located at 80 Km and 30 Km from shore, one 24″ main multi-phase sea line from CARINA-1 to Rio-Cullen production facility and one secondary 18″ line from ARIES jacket to the main pipe. The production scheme does not include offshore compression (Figure 2). In this context, limiting pressure drop from the sandy reservoirs up to the wellhead was paramount. Productivity oriented sand control technique and a 9″5/8 production tubing was then selected to maximize and ensure sustained wellhead pressure while minimizing the CAPEX. Flow Insurance Well "longevity" was another "key word" for the following reasons:Limited number of wells.Huge cost of work-over linked with rig and service equipment availability/mobilization because of extreme remoteness of the location (rig not scheduled in the area before five years after the end of current Total Austral drilling campaign). A Challenging Context Developmental problems to fulfill the above well requirements included:No or few case history for 9″5/8 completion and high velocity gas well horizontal sand control.The Extended Reach Departure nature of wells (Figure 3).A tight schedule between the drilling "go ahead" and the request for first gas delivery (18 months).A harsh environment location, remote from any offshore oilfield, over a day's sailing time to reach the operational base (Punta Quilla), in a tax free area with associated administrative issues, making logistics critical (Figure 4).Build/Re-build a learning curve (last Tierra del Fuego offshore campaign in 1997) with limited number of wells. Minimizing Technical Risk This was done through several actions:Purchase "best in class" products".Perform detailed and extensive Factory Acceptance Tests (FAT).Setup a workshop in the operational base, including a mobile test bunker and bucking machine to re-test all the critical assemblies before sending offshore.
A strategic well was drilled in 2001 (highly productive well with low CO2 content despite its age). A cellar cleaning campaign was performed on 03/2016, while the well was in production (450,000 sm3/day of gas). The 20" casing was found parted below the Starting Head at the cellar level, with evidence of corrosion. The cut had been buried in sediment for an unknown period and prolonged exposure to water and sediment accumulated in cellar was suspected. Wellhead movement due to thermal expansion (axial and lateral) was reported during monitoring. Additionally, annulus B, formed by the 13-3/8" casing × 9-5/8" casing annulus was pressured with 16 bars. The wellhead was found not directly supported by the landing base and axial/torsional force cycles during production/shutdown periods generated fatigue on the 20" casing. This load combination, added to lack of inspections and cleaning on cellar resulted in the failure of 20" casing at surface. Heavy workover remedial options were studied with prospective high costs and long delays. At the same time a Call for Tenders was launched to find solutions to safely put back well in production at the shortest possible delay. Boots & Coots/Halliburton proposal was selected for engineering and execution. The operation was treated as a Workover (well secured and capped with BOP). Main stages involved: Installation of Downhole plugs, monitor of annular pressures and bleed off operations.Surface installations removal. Cellar Floor and one wall removal (trench excavation).50 cm below cellar excavation to find 20" casing in good conditions. Cut corroded section of 20" casing.Build foundations and rig up Strand-Jack Crane. Cap well with BOP, install tensioning spool system and Tension the inner csg & tbg to 465 kips to get 34 mm displacement and compensate the thermal retraction (Engineering calculations using WellCat™ Software).Replace the 20" corroded section with 2 new half-moon 20" casing sections (welded).Finally release tension on an engineered landing base specially built for purpose. The objectives were fully achieved through this innovative and multidisciplinary engineering and operational approach. Three months of preparation and engineering were required. The operations were carried out safely (0 incidents) and cost effectively (heavy workover to change wellhead avoided). The well was re-connected and put back in production in April 2017. Production is currently at former levels (430,000 sm3/day peaks-choke not fully open).
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