A New Approach to Oil-and-Gas Exploration

How to achieve 50% reduction in offshore drilling costs

January 2015 | by Jack Kuhlman

Returns on capital in the oil and gas sector have halved since 2007, and even when the price of oil was $100 USD/bbl many operators were struggling to fulfill their capital commitments. Now that that the oil price has halved, it is clearer than ever before that there is a strong need for operators to transform their cost base. And well delivery, which on average accounts for forty to fifty percent of the capital spending for exploration and production, is a good starting point. We believes that the reduction potential can be as high as fifty percent when multiple levers can be optimized simultaneously.

Most operators have tried to curb their capital costs, most recently and particularly what they spend on drilling. Several operators have succeeded by focusing on operational improvements, such as reducing non-productive time, optimizing procurement practices or by better managing performance. 

Through our services to various operators around the globe, we have come to believe that in certain cases, it can be possible to achieve up to a fifty percent reduction on a costs per well basis across a portfolio of offshore wells. The full potential, however, depends on current performance and can only be achieved when an operator employs in concert most or all of the cost reduction levers we present here. Such an undertaking takes a great deal of effort and may generate resistance, but the potential upside obviouslyis huge.

For an average offshore operator, drilling and completion accounts for about forty to fifty percent of total capital expenditure; for many onshore operators, expenditures can be as high as sixty percent. These costs include different types of wells; production, development and exploration, and sometimes plugging and slot recovery too. On average, half of this cost is in leasing rigs and the remaining half is in equipment, engineering services, consumables and project management. For offshore wells, about seventy to eighty percent of these costs are time related, suggesting that any compression in delivery time will have a direct benefit to the bottom line.

In order to maximize cost reductions, a company needs to optimize these levers together:

Probably the most fundamental cost reduction driver is to drive learning curves rigorous portfolio and planning optimization at all levels to prevent overwork and make the learning curve less steep. Optimizing this lever can achieve an up to twenty to twenty-five percent reduction in the average cost per well. There are three elements to this driver:

  • Maintain a stable, overarching drilling portfolio plan for one-to-three years. A stable plan lays the foundation for long-range planning for all the stakeholders and suppliers for well delivery. The number one priority for many suppliers is to achieve better transparency and predictability in drilling activities. Transparency is critical. It allows all parties to improve planning and make their services more streamlined and efficient.
  • Stabilize well delivery plans for the entire drilling portfolio. Wells and their designs often depend on each other and plans tend to change based on the latest insights and developments. Therefore, drilling teams are often unable to plan in advance, resulting in suboptimal logistics and rig allocation. Locking in the drilling plan allows for optimizing rig allocation, rig movement, the logistics for specialized equipment and how a company mans its rigs. In order to stabilize the drilling plan and plan ahead, all stakeholders (for example, reservoir engineering, asset management, and drilling) need to align and commit to predetermined results.
  • Cluster similar wells in order to create repetitive jobs for drilling crews. Standardizing on well types reduces the amount of learning that a team has to do across a number of wells. Specialized crews should be able to get up to speed faster – and thus at lower cost – compared to regular teams. Examples indicate that drilling teams repeating very similar activities on ten or more wells become thirty to forty percent more efficient over just a few months than teams executing these activities for the first time or infrequently.
  • A clear baseline including improvement targets. A good baseline creates cost transparency within the organization and leadership and gives operators the ability to track well-cost improvements. As average well cost largely depends on the composition of the well portfolio, calculating improvements is not straightforward. To create realistic improvement targets requires a clear baseline of historic costs per well. The targets can be differentiated by geography and type of well, and by category of expense (rigs, third-party well services, consumables, internal engineering hours, and so on). Lastly, the results of any improvement initiative should differentiate benefits due to improvements in productivity and efficiency from those generated by changes in the well design, or even external, unrelated factors.
  • Procurement and Supply chain management can take operators some of the way toward the fifty percent reduction target in drilling costs – about up to ten to fifteen percent. More advanced project management practices include working closely with rig operators to develop designs and drilling approaches that remove idle time, reduce the use of third party services and expensive downhole equipment, and increase drilling speed.
  • Rigorous productivity management is required to revitalize the performance drive, and that alone has been proven to reduce up to five to ten percent of the well cost. As wells are hard to compare, and operators perceive each drilling job as very different, they tend to resist ambitious targets for time improvements. However, it becomes far easier to set bold targets when the drilling plan is standardized and optimized for recurring jobs.

Even though optimizing all these cost-reduction levers in a single effort might seem hard, it is possible. As internal resistance to changes in well delivery is likely to be high, it’s critical for senior management to get behind any initiative. Management should clearly define and communicate the organization’s needs and prepare a clear change story to translate well-cost targets into the budgets and goals for both the well delivery organization and the asset management team. If those teams retain the budget and freedom to continue their old practices, it is unlikely they will agree to implement simplified well concepts or push for improvements.

Rig release strategy.  A reduction in average well cost does not translate automatically into a bottom line capital expenditure reduction unless the company executes a robust rig release strategy. Remember: Because most costs are time-related, cutting average costs by reducing complexity and introducing lean measures will only result in freed up rig capacity. For cost-per-well savings to translate into bottom line savings, the total rig spend needs to go down. For most mobile rigs, cold stacking does not result in bottom line savings. Rather, reducing the total number of rigs is the most effective way to realize bottom line savings. However, as contract lead times tend to be long, it is important that operators identify the number of rigs they should release at an early stage.

Obviously, there are barriers to achieving a 50% reduction of well costs. The most important may be the perceived or real lack of flexibility in the organization’s approach to delivering wells. When optimization is focused solely on delivering the well fast in a resource-constrained but high-oil-price context, continuous improvement and customization of well designs and specifications make sense. However, it is our experience that companies manage, and in most cases reduce, customization, particularly when it occurs late in the engineering and planning process and affects costs the most.


Executive Editor

Ms Anna Sullivan

Ms Anna Sullivan