New Well Architectures Increase Gas Recovery and Reduce Drilling Costs

Abstract

SPE/IADC Members Abstract This paper describes the evolution of the production well architectures in the Bongkot field, with its consequent improved hydrocarbon recovery and drilling costs savings. The classic production wells in Bongkot gas field had a multi-zone architecture. In four years the evolution of the well architecture has increased the gas recovery by 5% and reduced the drilling and completion costs by 50%. This has been achieved through the implementation of a monobore approach. A further advantage is the potential for conductor pipe sharing allowing the doubling of the old platforms design capacity in the medium term, and reduced platform size in the longer term. This new architecture was first implemented on prototype well BK-4-C, completed in May 1996. With a total drilling, logging and completion duration of 11.6 days and a potential productivity of 11 million standard cubic feet per day (MMscf/d), this prototype shows a total cost 5% lower than the average Bongkot development well. This new architecture allows rigless perforations, saving 25% on the tubulars and 30% on oil based mud. Large scale implementation of this new architecture on the Bongkot field has now begun. Introduction Background. The Bongkot field is located offshore in the Gulf of Thailand approximately 600 kilometres (km) South of Bangkok and 180 km off the coast of Songkhla, in concession areas B15, B16 and B17 (Fig. 1). The field was first discovered in 1973, and was subsequently delineated with 23 wells. In 1988 the Thai government assigned the concession development rights to the PTT Exploration and Production Co. Ltd (PTTEP). After consultations with several companies, Total was selected as the main partner and operator in charge of the development of the Bongkot field. The concession joint venture partners are PTTEP (40%), Total Exploration and Production Thailand (30%), British Gas Thailand (20%) and Statoil Thailand (10%). Geological Context. As currently delineated, the field extends over an area of 450 square km, with a length of 70 km and a width of 5 km to 12 km. Proven reserves were certified at 3 trillion standard cubic feet in 1994. Water depth over the field varies between 75 and 80 metres (m). The hydrocarbon reserves are found in multi-faulted sandstone reservoirs of the Oligocene and Miocene Age, deposited in fluvio-deltaic and coastal environments (Fig. 2.). These reservoirs are found over a large range of true vertical depth (TVD) from 1000 to 3000m below mean sea level. The hydrocarbon contains carbon dioxide (CO2) in concentrations varying from 2% to 60% depending on the compartment and zone. All reservoirs developed to date have had a hydrostatic pressure regime. Field Development Strategy. The field has been developed with a single production platform and a series of satellite 12 slot wellhead platforms (WP). Drilling and completion operations are carried out with a self erecting tender barge, which installs a rig package on the wellhead platforms for the duration of the drilling operations. After departure of the rig well servicing can be performed from the platform using slickline, electric line and coiled tubing. At the end of the second phase of development 8 wellhead platforms had been installed (Fig. 3). The development has been phased as follows: Phase I. Consisted of the installation of 3 wellhead platforms and the drilling of 29 deviated gas production wells. Following the installation of production facilities, the field came on stream in July 1993 producing 150 MMscf/d of gas and 3,300 barrels/day (bbl/d) of condensate. From February 1994 the flowrate was increased to 200 MMscf/d of gas and 4,000 bbl/d of liquids. P. 351^