Reservoir Study Considering a TLP and Dry-Completion Development for a Deep Offshore Heavy Oil Field

Abstract

The continuous search for new oil resources is driving the major companies to start considering the development of offshore heavy oils (OHO) fields. Although not as heavy as inland heavy oil fields, where thermal methods are usually employed, development of these fields imposes extra technical difficulties as waterflooding might be the only feasible economical alternative for increasing recoveries. The process is used in association with long horizontal production and injection wells carefully placed in order to take advantage of the geological setting. OHO projects may face several production related problems during their lifetime, such as early water breakthrough and increasingly fast water rates. Other problems may also arise: strong water-oil emulsions, flow assurance problems related to hydrates, poor gas lift efficiency opposed to a less reliable satellite wells electrical submersible pumps (ESP) technology. Moreover, most offshore developments are based on FPSO production systems and satellite wells where one has limited (and highly expensive) well access. The reservoir study described in this paper quantifies the worth of reservoir management actions that would be feasible in a TLP production system equipped with drilling and workover capabilities. This work focuses on the optimization of a development plan using different technologies such as side tracking existing wells, multilateral wells, ESPs, etc. A thorough discussion on the impact of operational efficiency factors (downtime factors) is also offered. The methodology described in this paper is applied to a full scale reservoir flow model that was continually history matched with oil/gas/water flow rates and measured downhole pressure data, gathered by a one well pilot production system for over a year period. The results of the study are interpreted in terms of the scenarios more suitable for TLP developments. The benefits are directly related to the complexity of the reservoir geology which, in turn, governs the possibility of field development by phases. Other aspects such as the existence of pipeline infrastructure nearby the field and use of innovative artificial lift systems may either help or impair the use of dry completion wells concept. Although the present study reveals the FPSO option as the best economical alternative, for the particular field investigated, this work sets a standard for future OHO development studies. Introduction Exploration efforts offshore Brazil have been indicating important heavy oil discoveries in reservoirs that are often located in deep waters. In this paper, the terminology "offshore heavy oil" is applicable to oils with an API below 20, with viscosities at reservoirs conditions over 10 cp and surface viscosities over 500 cp. The economic exploitation of these reservoirs presents a series of technological (and economic) challenges that are very properly addressed in the literature (1, 2).Deepwater fields are often developed through floating systems using FPSO or SS type platforms, with subsea well completion (satellite wells).However, this development concept hinders well workovers due to high costs and limited availability of workover rigs with dynamic positioning facilities.This is results in fewer possibilities for an active management of producing reservoirs. A flexible and timely reservoir management is particularly important for heavy oil reservoirs, as they present early water production problems, with lower recovery rates and associated flow assurance problems.

The Challenges of Developing a Deep Offshore Heavy-Oil Field in Campos Basin

“…The positioning of the wells was based on a reservoir integrated quality map (IQM) 5 . The IQM is generated computing data related to oil production efficiency, including static and dynamic factors: rock quality in terms of permeability and porosity, mobile oil saturation, net thickness, distance to a water / oil contact and fractional oil flow.…”