Digital Transformation Increases Value in an Omani Thermal EOR Asset
Authors: Carpenter Chris 
Published: May 2019

This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper SPE 190419, “Increasing Value Through Digital Transformation: A Case Study From the A Field EOR Asset, Sultanate of Oman,” by S. Holyoak, SPE, A. Alwazeer, S. Choudhury, M. Sawafi, A. Belghache, T. Aulaqi, SPE, S. Bahri, R. Yazidi, A. Yahyai, and K. D’Amours, Petroleum Development Oman, prepared for the 2018 SPE EOR Conference at Oil and Gas West Asia, Muscat, Oman, 26–28 March. The paper has not been peer reviewed.

A thermal asset in Oman is characterized by a large-scale steam-drive/cyclic-steam-soak (CSS) development project, underpinned by extensive data gathering. Efficient execution of data management and analysis within a visualization-intensive, collaborative work environment is critical to success. In this paper, the authors aim to demonstrate that working in this manner enables rapid identification and execution of cost-effective optimization opportunities and risk reduction.

Introduction

The A West and A East fields are located in the south of Oman. Thick, high net-to-gross sandstones belonging to the Haima Group form the main reservoir unit. The targeted Haima oil is heavy, with viscosities increasing with depth, and reaching up to 400 000 cp close to the oil/water contact (OWC) at the A East field.

Following 25 years of cold production at A West, a development plan addressing thermal redevelopment for both fields was approved in 2009. In A West, a steam-drive pilot began in 2008, whereas, in A East, with its limited production history, CSS was selected for initial production and started in 2014.

Thermal development is characterized by operational complexity and high well counts. Currently, almost 500 wellbores exist in A Field (including sidetracks). The wells are closely spaced, typically 50–100 m at the top reservoir level. Expansion and infill of the development is ongoing, and the well count is increasing steadily. A challenging environment exists for maximizing oil recovery in a safe, manpower-efficient, and cost-effective manner.

On an annual basis, the asset’s decision-based surveillance plan is reviewed, challenged, and updated as required. The execution of this plan, together with incorporation of the field’s reservoir-performance data, translates to a significant amount of diverse information acquired on a daily basis. A combination of highly visual tools and innovative processes is used in a cross-disciplinary work environment to facilitate effective management and analysis of this data.

Data Collection and Transmission

This section provides three examples of current methods used to acquire and transmit data related to A Field’s reservoir integrity, thermal response, and production metrics.

Microseismic. Microseismic wells are being used in other thermal-development projects to monitor for fracturing and fault reactivation. Typically, an array of geophones is cemented into a dedicated wellbore with a data-transmission cable to surface. A microseismic event created by induced fracturing, for example, is detected by the geophones across one or more monitoring wells. Signal processing allows the location, magnitude, and character of the events to be derived. To assess the feasibility of replicating this approach in A Field, additional modeling was carried out, varying the number and placement of the monitoring wells. This showed that the main development areas of A West and A East fields could be covered with six microseismic wells, with three in each field. Furthermore, modeling indicated favorable detection thresholds and event accuracy with this six-well scenario.