Acquisitions are a good time to automate operations

Mark Goloby, TC Technologies, Houston

In today’s dynamic energy exploitation industry, distinguishing large producers from small producers is not as straightforward as it once was. It seems with every acquisition the acquiring company will realign and divest producing assets to meet new strategic directives. Within this process, a “small” producer can suddenly find itself owning a very large producing field.

In many circumstances, the previous “large” producer owner will have implemented automation capabilities unfamiliar to the smaller producer. While the value of such automation is rarely considered in evaluating the acquisition, the labor savings and capabilities such automation delivers will play a significant role in the “small” producer successfully operating its newly acquired production.

However, for many “small” producers this may be their first direct experience with the capabilities and solutions these tools can bring to their operations. The good news is, more than likely, many of its employees have been with companies utilizing automation. As a company however, transitioning from manual processes to automated processes can be somewhat of a culture shock.

Any “small” producer whose corporate vision is to become a “large” producer must ascertain its current methodology for data gathering and operations monitoring. Reduction of LOE costs, maximization of labor in a tightening labor market, and the overall desire for best of practice are all essential to successfully bringing this vision into focus.

The most important aspect for success is senior management’s commitment to implement an automation plan. A large acquisition can be the very catalyst needed to get such an endeavor kick started and the resources allocated to ensure success on both the newly acquired production and the legacy fields.

So, the small producer has made its acquisition. As with any such endeavor, the close is really the opening of how to operate these assets efficiently. The first step requires critical thinking and a list of functionally focused questions:

1. What is the current the data gathering methodology?
2. How integrated is the data gathering automation into operational automation?
3. IS further automation possible?
4. How does the automation of the acquired properties fit with legacy production?
5. How to insure that the investment in automation will provide for individual well optimization?

The first question can only be answered with two functional audits: one, the data path of production data from the wellhead to operations; two, from the wellhead to financial reporting. The benefits of this step are exponential. Performed correctly, many of the intricacies of day-to-day operations of the acquired properties will come to light.

It is within this investigation that the personnel coming with the acquisition can contribute mightily and will be more than forthcoming on inefficiencies and holes in their system that may have been ignored or suppressed under the prior regime. In one pass, the acquiring company will learn the existing data acquisition system, uncover existing inefficiencies therein, and identify the direction to take their automation plan.

The next aspect can be a bit trickier. Primarily because it is an aspect the industry is grappling with as a whole. Industry wide, oil and gas companies tend to treat field reporting and financial reporting as two independent functions. Tracing a molecule of gas or drop of oil from wellhead to end user is clearly understood, following that same molecule through to the income statement, a bit fuzzier. Field data is integrated into operations, engineering, and marketing. Financial reporting will get some of its data from the field, but will focus on the revenue reporting it gets from its oil or gas purchaser.

Some companies may perform a reconciliation of these two production values; others may intend to, but rarely allot the time. This is where the capabilities of today’s technologies prove their significant value. With technology that delivers measurement and reporting to both the production accounting as well as the financial accounting, many discrepancies inherent under the old data gathering and reporting will disappear.

With a plan in hand to address the acquired production, the next step is to address the legacy properties. In many cases, these properties will have little if any automation installed. The challenge is to identify custody transfer points, critical decision points within these systems, and the operating data elements in need of automation.

Two fundamental characteristics regarding the automation of the legacy fields: One, the field will typically be beyond its prime production so the costs of automation are spread across lower production activity. Two, the dollars to implement will come from CAPEX. That may require convincing other participants that the spending is warranted. While industry studies routinely demonstrate that these tools bring 10% to 15% increases to the bottom line via optimized production and decreased administrative costs, it requires a firmness and discipline from the CEO on down to be implemented.

Fortunately there is plenty of evidence available to support this visionary CEO. There are three ways those who have pioneered these efforts get their payback:

Management by exception

Pumpers, contract or employee, can identify underperforming wells and plan their immediate morning activity accordingly. Wells in need of attention are addressed sooner, bringing a well back to its optimal production sometimes 8 hours sooner and in some cases days. A recent finding mentioned that at today’s costs of operating it will take at least $70/bbl oil to match the margins achieved at $35/bbl. Now is the time to invest in what today’s technology can deliver. The companies that invest in automation now will have lower LOE costs to survive at $60 or maybe even $55 bbl prices.