Sand Control Robustness in a Deepwater Development: Case Histories From Girassol Field (Angola)

Abstract

Wells in the Girassol field, offshore Angola, are situated in very deep water and have being completed in unconsolidated sandy turbiditic reservoirs. Today in Girassol which includes also Jasmin reservoir, 29 wells have been completed and connected to production facilities and pressure maintenance is coming from 13 water injectors and 2 gas injectors. The completion strategies employed have included mainly stand alone screens in open hole and cased hole frac-packs. A review of the design for both producers and injectors, along with the criteria related to the sand characteristics, and off-shore implementation of the completions will be described. Production strategy recommendations to minimize the sand risk during well start-up and ramp-up and also well steady-state production will be given. This paper will provide an overview of the behavior of both sand control techniques after 5 years of production and injection. An in depth analysis of the different productivity/injectivity characteristics such as drawdown values applied and PLT observations during these 5 years allow us to draw some general recommendations for these types of sand control techniques when used in a similar geological environment. Impact of the measured drawdown values, on the sand control robustness will be described. Introduction The Girassol fields were discovered in May 1996 and were appraised in 1997 with two additional wells. Fields are in Block 17, located offshore Angola, 210 km northwest of Luanda, in water from 1,250 to 1,400 m (Fig. 1). Girassol field is one of several fields in this prolific block and Jasmin is considered as part of the same reservoir. 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 (10%). High productivity provided with horizontal drains allows to significantly reduce the number of well. It is a full subsea development tied back to spread-moored floating production storage and offloading (FPSO) unit (Fig. 2). 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 40,000 barrels of oil per day (BOPD), because of the excellent reservoir characteristics. Pressure maintenance of the field is achieved with seawater injection and re-injection of produced gas for a limited time. The variations expected in sand qualities and reservoir configurations indicated that more than one completion method would likely be required. Field Geologic and Reservoir Description The Girassol/Jasmim reservoirs in this field consist of unconsolidated fine to very coarse sands deposited on the Block 17 area after passing through the canyon of the Congo River. Girassol/Jasmim Oligocene structure evolution is driven by gravity tectonic evolution. Late Cretaceous to Oligocene is characterized by the development of a NW-SE trough bounded by passive salt ridges. The Upper Oligocene corresponds to the deposition of turbidites along NE-SW channelized systems within this NW-SE basin between peripheral salt ridges.