Guest Editorial: What Exactly Is ‘Non-Production Data’ and Why Should It Matter to Operators?

Abstract

_ More than likely, operators have acquired production data on their wells since their inception. Tremendous money has been spent on building out sophisticated production data systems to track and report current production trends, as well as future projections related to the reserves these companies have found and proven. While all these insights are beneficial, they do not paint the full picture as to the value of a well. To understand the real valuation, operators should be looking at their complete value chain of data. The lack of attention to non-production data is costing companies millions of real dollars in M&A valuation and return on investment from operating. Non-production data are produced by original equipment manufacturers (OEMs) and service companies. This data set provides a clearer understanding of the cost to drill, challenges associated with specific equipment, and lessons learned. Until recently, these data have been considered a responsibility of the service providers; however, this has led to inconsistent formats, or missing information altogether. As M&A deals are likely to accelerate in the foreseeable future, E&Ps looking to sell would be wise to pay attention to holistic data sets and use them as a bargaining chip at the valuation table. Non‑production data will prove significantly valuable when it is time to extract the value of a field, particularly if it is accounted for, standardized, and catalogued to prove out formations. Historical data for bottomhole assemblies (BHA) alone can help better inform drilling contractors on equipment wear and tear, performance in a given formation, and other valuable insights into a particular drilling program. The Complete Value Chain of Data According to Seeking Alpha, drilling can make up 40% of the total cost to bring a well online, with the average well cost in the Permian Basin ranging from approximately $5.0 million to $9.3 million as of 2017. This means drilling costs could be as high as $3.72 million per well—and these numbers are pre‑COVID pandemic and pre‑inflation. Many of the onshore wells brought online today are not produced by the original E&Ps that discovered the assets, but instead by the latest buyer. When the purchase was made, significant diligence was done to ensure the production data were correct. Unfortunately, many details and lessons learned during the drilling process were not kept as part of that acquisition, so the new owners were left to potentially solve the same problems again. Those reinvestments can be further compounded by the costly current state of the industry. The missing details and lessons learned referenced above include the terabytes of information from the multitude of service companies involved in originally bringing that well online. Data such as mud characteristics, BHA tool configurations, well plan deviations, casing and cementing solutions, as well as mud weight or size of the motor, may be recorded in a software such as WellView. But what about the specific configuration data such as power‑section fit, stabilizer shape, hard‑banding material, or bit-to-bend length, just to reference a few? These data points are often adjusted and dialed-in over time to find just the right recipe for a specific area. Unfortunately, this information never makes it into the official logs or databases of the operating company.