First Application of Novel Microemulsion Technology for Sand Control Remediation Operations—A Successful Case History from the Rosa Field, a Deepwater Development Project in Angola

Abstract

This paper documents a novel engineering approach and the operational methodology used to achieve high efficiency remediation on two offshore applications. Results are presented, detailing specific placement procedures, in-situ treatment design and productivity improvements. Two wells were recently drilled and completed for the Rosa deepwater project, Block 17 offshore Angola, using a Non-Aromatic Oil-Based Mud (NAOBM) weighted with sized calcium carbonate. After installing the Stand-Alone-Screens (SAS) across the production intervals and allowing the wells to cleanup, the Productivity Index (PI) measured on each well was very disappointing. A diagnosis study concluded that the severe productivity impairment on these wells was related to either screen plugging by mud particles while running the screens to bottom in the NAOBM and/or the plugging induced by a mixture of formation sand, mud, and filter cake when draw-down was applied during cleanups. Based on collaborative laboratory work between the operator and a service company to design a treatment fluid for removing NAOBM filter cake material for water injection wells, a microemulsion spotting fluid was formulated to remediate the damage in the two Rosa wells. The formulation contains a surfactants blend, acetic acid, and brine. The remediation was performed using a Coiled Tubing (CT) equipped with a rotating jet blaster to spot the treatment fluid inside the screen assemblies. Each treatment was allowed to soak. After the placement of the treatment pills on each well, cleanup measurements indicated significant PI improvements close to expected values. Production Logging Tests (PLT) analysis indicates that both wells are producing from almost all screen lengths. Despite the challenging placement of the treatment fluid in the SAS assembly, the diffusion of the microemulsion with acid allowed break up and removal of blocking solids from the completion screens and filter cake residues from the wellbore walls, allowing full production. Introduction The Rosa field was discovered in January 1998 with the Rosa 1 well and was appraised with two additional wells at the beginning of year 1999 and at the end of 2000. The field is located in Block 17, offshore Angola, 210 km northwest of Luanda, in average water depth of 1,400 m (Fig. 1). Rosa field is one of several fields in this prolific block. Under a production sharing agreement with Sociedade Nacional de CombustÍveis de Angola (SONANGOL), the Angolan state oil company, partners in the field include Total E&P Angola (40%, operator), Esso Exploration Angola (Block 17) Ltd (20%), BP Exploration (Angola) Ltd (16.7%), Statoil Angola Block 17 A.S (13.3%), and Norsk Hydro Dezassete A.S. (10%). After analysing several development options, the solution chosen was subsea development and connection of the field (tie-back) via subsea pipelines to the Girassol Floating Production Storage and Offloading (FPSO) unit located at a distance of between 15 and 20 km from Rosa, with new installations on the FPSO unit for processing the production from Rosa (Fig. 2). The adopted development scheme includes the drilling, in the base case, of 25 wells (14 production wells and 11 water injection wells). Production from the Rosa site is scheduled to begin during the 2nd quarter 2007. All reservoirs in this field are constituted of highly unconsolidated sands, which require the wells to be completed with sand-control techniques. The wells have high productivity, up to 30,000 Barrels of Oil Per Day (BOPD), because of the excellent reservoir characteristics. Pressure maintenance of the field is achieved with seawater injection. Field Geologic and Reservoir Description The Rosa Upper Oligocene structure is constituted of Rosa D and Rosa E main channels above the Rosa D West secondary channel. The Upper Oligocene corresponds to the deposition of turbidites along NE-SW channelized systems within this NW-SE basin between peripheral salt ridges.

Improving Well Productivity/Injectivity on Deepwater Offshore Horizontal Drains

“…A soaking period of 16 hours was applied before cleaning up the well again and re-testing. In both cases the treatment was re-applied and an improvement seen after each treatment by a significant factor [Lavoix et al 2007].…”

“…o Low inclination already pointed out on the Rosa wells [Lavoix et al 2007] o Screen diameter vs. open hole diameter • Screen type (latest evidence suggests the premium mesh is not an additional impairment factor)…”

“…Within Block 17, impairment issues were initially raised on the Rosa field in 2006, and a novel microemulsion fluid was developed with an associated service company for treatment of the wells. Successful remedial treatment with coiled tubing was carried out on the two Rosa producer wells in 2007, the results of which were discussed in SPE 107341 [Lavoix et al 2007]. The main reasons for impairment were investigated in more depth as part of a diagnostic study, where various potential causes were raised.…”

Evaluation of Nonreactive Aqueous Spacer Fluids for Oil-based Mud Displacement in Open Hole Horizontal Wells

“…With the advent of microemulsion technology, nonreactive aqueous treatment fluids can be customized to achieve a relatively more effective well cleanup. Microemulsions are thermodynamically stabilized multicomponent fluids composed of oil, water and surfactant blends, which solubilize the oil component of the OBM with limited mechanical agitation [16][17][18][19][20][21][22] . Since acid-free microemulsion fluids are incapable of dissolving OBM solid particles, it is critical that dispersed residual filter cake solids are able to flow through the sand screen completion apertures when used in standalone screen completions.…”

Enhanced Oil Solubilization Using Microemulsions With Linkers

“…This application includes near-wellbore cleanup to prevent or remediate formation damage, and effective displacement of synthetic or oil-based mud to water-based fluids to minimize non-productive time, reduce waste volume, prevent cement failures and reduce the risk of tool complications during the completion of a well (Penny et al 2005;Lavoix et al 2007;Quintero et al 2005;Quintero et al 2009). …”