Colombian oilfield reverses downward trends, digitally

London – Exploration and production company Hocol SA operates four production fields, currently generating 30k barrels per day, in the remote region of the upper Magdalena River valley in the Colombian Andes mountain range.

Back in 2008, after consistent field output and productivity declines, Hocol took action to reverse the downward trend and by improving the efficiency and cost effectiveness of its production fields — San Francisco, Balcon, Palermo, and Monal.

This required a thorough overhaul of the processes and technologies in the oilfield. Hocol also needed to supply the oilfield operators with the tools necessary to be more efficient and productive.

As field output declined over the course of several years, Hocol employed a mixture of various forms of production techniques in an attempt to spur recovery.

The company took a progressive approach in its operations and its mitigation strategies, and tried to employ various secondary recovery techniques, such as water flooding, to increase oil recovery.

Hocol also tried water alternating with gas injection wells, and the company also drilled horizontal and highly deviated wells to help increase the reservoir recovery potential, but these techniques failed to provide the overall total solution the company sought.

The four fields featured a mixture of different types of wells, including primary production wells, along with wells that employed electric submersible pumps with variable speed drives, wells with progressive cavity pumps, and wells with walking beam pumps.

Hocol found this mixture of wells led to increased demand on operational surveillance. This, coupled with the decline in output, led Hocol to tackle the issue from a different angle.

Approach overhaul

Hocol looked to increase production efficiency, reliability and safety by working to improve operator effectiveness with improved technologies and processes. To achieve this, the company sought to accomplish several major objectives.

First, in order to increase production and improve operator effectiveness, Hocol needed to secure a way to better visualize well conditions and obtain status information about the producing wells. This would enable operators to make more timely and qualified production decisions.

Also, operational personnel spent three quarters of their time on routine rounds and well surveillance, driving from field to field in pickup trucks to check operations. This time on the road also increased the chance of driving accidents.

As a result, Hocol sought to reduce these routine rounds for operational personnel without adversely affecting well performance. Ideally, eliminating routine well surveillance rounds would free up valuable operator time to concentrate on activities to help increase production, as well as increasing safety.

Hocol tasked service provider Equipo Y Controles (ECI) with eliminating routine rounds, increasing production visualization and installing the technology necessary to enable remote operations. ECI began its work to help achieve Hocol’s objectives by surveying the four production fields.

During the survey, ECI found 36 well pads with groups of four or five oil wells feeding into one of four production centers. Each well pad was connected to a mixture of well types. For optimal results, well pad operation must be autonomous.

Specifically, nearly 110 producing wells comprised the fields and tied into a production facility. This included a mixture of production types — and each with their own distinct nuances. The types included:

• Primary producer wells, where oil comes to the surface under its own power;
• Gas-lift wells, which employ gas injection to lift the producing emulsion to the surface;
• Wells that employed electric submersiblepumps (ESP) and variable speed drives (VSD) to mechanically life oil to the surface;
• Wells that employed progressive cavity pumps to also mechanically lift oil to the surface;  and
• Donkey pump wells, which use a surface walking beam to move a sucker rod that powers a down-hole pump to lift oil to the surface.

The oilfield’s 36 well pads, evenly spread among the four production facilities, required complex SCADA information exchanges in order to remain productive. In addition, ECI found the ESP and VSD systems used on some of the producing wells lacked electric interfaces to enable operator insight.

Tighter connections

ECI’s answer to improving Hocol’s oilfield output came in the form of a digital oilfield solution using Honeywell technology.

For the well pads, this meant equipping each one with a PLC that used wireless technology to communicate with field transmitters. ECI also installed hardwired interfaces to individual well VSDs, which enabled speed changes and also provided the ability to economically capture speed, frequency and power information.

The topology of the Hocol oilfields also played an influential role in the type of new technology ECI chose to install. The rugged terrain and surrounding vegetation made conditions unfavorable for long distance point-to-point or multipoint communications, so ECI chose to enlist satellite communications for gathering the well pad information from the controllers.

This approach provides flexibility for adding or deleting wells from the system, and also makes it easier to change production methods and enables greater operator control.

A resident redundant Honeywell controller manages production at the well pads. Any well pad information — along with control set-point changes and actions from remote control rooms and geographically-dispersed engineering discipline centers — are easily communicated via satellite.

Overall, this approach means Hocol’s SCADA application uses satellite communications to connect the right information to the right point in the system, instead of relying on traditional hard-wired transmitters to route information to the appropriate end user.

With the new system, a very small aperture terminal (VSAT) satellite communications system facilitates information exchange between various well pads, production facilities centers and remote engineering centers.

Data service units communicate with an outside antenna equipped with a transceiver. The transceiver receives or sends a signal to a satellite transponder, which, in turn, sends and receives signals from an earth station computer that acts as a hub for this system.

Each end user is interconnected to the hub station via satellite in a star topology. This means that for one end user to communicate with another, each transmission has to first go to the hub station, which retransmits it via satellite to the other end user’s VSAT, which handles data, voice, and video signals.

Honeywell wireless field transmitters, which are installed at the well heads, collect and load process information into a Honeywell PLC, providing more flexibility than traditionally-used copper cable runs and ancillary cable trays.

Remote control

Redundant Honeywell Experion servers located at this hub enable communications between well pads and remote users and remote production facilities, as well as a Honeywell e-server connection that provides a way for remote engineering services, like well surveillance, to monitor and send set points to specific wells.

The e-server interfaces to the Internet, and this connection allows remote engineering services to monitor and send set points to specific wells.  The e-server also extends to production facilities, making control and surveillance information readily available to operators. This type of connection provides a means for remote engineering service providers to make well performance recommendations and highlight abnormal events. 

This tighter remote link facilitates better communications, which is critical for remote monitoring. For example, Hocol has a performance contract with a well service surveillance provider for its electric submersible pumps and progressive cavity pumps, which requires a high degree of remote surveillance to ensure optimum well performance. With this new remote connection, the service provider can more easily monitor well performance.

The digital oilfield’s wireless features also extend to hazardous areas, where Hocol is now using industrially-hardened wireless transmitters. The Honeywell XYR6000 transmitters — mounted directly on the wellhead — help monitor variables within the area by acquiring process measurements like differential pressures and temperatures directly from the wellhead.

A broader OneWireless network helps transmit this information for operators to easily compile and review.

This wireless arrangement provides flexibility and expansion capabilities around the system’s well heads, and it also simplifies the process of adding or changing wells by minimizing associated logistical requirements. For example, the system makes it simpler to change a well’s recovery method with minimal impact to the automation configurations. 

Efficiency gains

To date, Hocol’s digital oilfield has delivered results that point to a reversal in the company’s previous downward trend. Within six months, Hocol was able to reverse the downward trend of the oilfields’ output with the new implementation, and the company credits the improved insight and communication offered by the new system.

With this increased system-wide insight enabled by the digital technology, operators are now tapping into a wealth of data previously unavailable. And this insight is improving overall efficiency and, as a result, field output.

Before, nearly seventy five percent of Hocol personnel dedicated time to routine operation rounds, physically driving from oilfield to oilfield. With the wireless technology now in place and forming the backbone of the digital oilfield, routine operator rounds have been reduced, allowing Hocol operators to concentrate on activities that impact production efficiencies.

Also, the addition of tight remote surveillance capabilities to the production and engineering centers is providing a high degree of situational awareness and enabling more proactive responses to abnormal situations.

The company estimates that facilitating quicker and more appropriate responses to abnormal well performance may mitigate the loss of millions of dollars per day.