Enhanced recovery

Digital Transformation Increases Value in an Omani Thermal EOR Asset

A thermal asset in Oman is characterized by a large-scale steam-drive/cyclic-steam-soak development project, underpinned by extensive data gathering.


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.


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.

The cost-effective wells were drilled in the last quarter of 2016, with the geophone arrays attached to inspected 2⅞‑in. tubing. The 10-geophone array mainly was positioned across 8½-in. open hole, but, because of depth constraints, the upper geophones were positioned behind 9⅝-in. casing. Coupling of the geophones to the host rock formation is critical to achieving good data quality. As part of the process of assuring well integrity, a cement-bond log was run across the cemented 9⅝-in. casing. The same log was also used to optimize the geophone positions with reference to the areas of the casing with the highest-quality cement bond.

The wells were set up with solar-­powered wireless data transmission from the wellhead to a data-storage bank at a field-control center. From there, the data were transferred to the team’s geophysical contractor in Canada for signal processing. Daily reports were transmitted back to key operator staff for review, and automated alarms were triggered when signal characteristics exceeded predefined operating envelopes. Like the daily reports, these were communicated by autogenerated emails. The acquisition system can be accessed at any time to check network integrity and data-streaming capability. This system has now been operational since the first quarter of 2017, with excellent system uptime achieved to date.

Downhole Fiber Optics. Since the early stages of the thermal-development process, fiber-optic cable (FOC) has been operational in several observation wells in A Field between the injectors and producers. These encompass both distributed temperature sensing (DTS) and distributed acoustic sensing (DAS) functionality. At A Field, the FOC is attached to the tubing string and is terminated at a surface junction box.

DTS. DTS allows monitoring of the overall thermal response at the observation well, in addition to obtaining a detailed vertical temperature profile. The presence of reservoir barriers to heat flow is highlighted as well as whether the reservoir is heating evenly. On the basis of the response, the injection or offtake strategy can be modified accordingly. Data is transmitted to the DTS database through the operator’s network.

DAS. DAS wells have been used to record a 4D vertical seismic profile (VSP) survey in A West to track steam-chest development. This dispenses with the need to deploy conventional geophones downhole. From 2009 to 2012, three multiwell VSP surveys were recorded with a conventional approach using a surface source and downhole geophones. At the time of the last geophone-based survey in April 2012, the feasibility of signal acquisition using permanently installed DAS FOC was assessed. This effort was deemed successful, and, as a result, FOC was installed in an additional seven wells. A DAS 3D VSP survey subsequently was acquired in 2014 across the eight wells.

Automated Well Tests. The asset is also moving toward automated well tests, which, at the time of writing, are fully operational in A East. Following transmission to the corporate database, gross and net oil and water-production splits are automatically assigned, ready for viewing in visualization applications. Integration with downstream data from the area production station allows reconciled oil to be calculated.

Data Insights: Speed and Access

Once the data have been acquired, a range of in-house tools and platforms are used to facilitate efficient analysis, resulting in actionable insights. These tools are discussed in detail in the complete paper.

The asset team maintains a strong focus on accessible, highly visual platforms. Together with a full-field subsurface model, these work from common databases to view, integrate, and analyze data rapidly. In addition to the operator’s production-surveillance platform, the team uses a commercial visualization platform to improve the efficiency of field, pattern, and well reviews. Preparation for these events can be very time-consuming. In A Field, the platform has been set up with diagnostic plots and map templates populated with the latest data. In addition to time savings, this also creates consistency, and anomalous production behavior can be identified readily.

Full-Field, Full-Stratigraphy Live Subsurface Model. Another tool vital for data integration and visualization is the full-field, full-stratigraphy live subsurface model built within the asset (Fig. 1). Corporate reference projects, linked to operator databases, allow rapid updating of the project to reflect the latest data, which are integrated with current seismic interpretations plus geological and production insights. Automated work flows facilitate quick and easy model updates, highlighting opportunities and reducing uncertainty continuously. Several positive effects of these practices have been noted.

  • On running the model-update work flow, both depth structure and pore-fill maps for the entire stratigraphic range are also updated and sent automatically to a shared drive.
  • Well planning and report writing, including annual hydrocarbon volume reporting, is facilitated by the ability to quickly generate maps, sections, and correlation panels.
  • The model highlights the potential of the secondary reservoirs at A Field and enables associated in-place hydrocarbon-volume ranges to be assessed quickly.
  • Because the evaluation extended beyond the field boundaries, additional near-field opportunities were identified and are being matured.
Fig. 1—Full-field, full-stratigraphy model for A Field.

Additional Positive Effects

These applications are having a tangible effect on production; efficiency; and health, safety, and environmental (HSE) concerns. Daily reporting is now established at A Field. The first version of a traffic-light system has been developed wherein exceeding predefined microseismic activity levels and characteristics will trigger a move from green status through to amber or red. Together with the asset’s geomechanical models, these will allow management of production and injection parameters to reduce HSE risk.

Data gathering can be costly. The project team therefore attaches high importance to ensuring that data acquisition is performed on a need-to-have basis, and the data must add (or safeguard) sufficient value to justify the expense. The automation, data-­integration, manipulation, and visualization tools described in the complete paper offer excellent return on investment. An application that automates the pumping rate, for example, involved a low capital outlay, but subsequent manpower savings have been estimated at 20%. In A West, the implementation of this same application resulted in a 35% increase in oil rate.

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.