A company that drills wells and tries to beat its previous performance in terms of cost, drilling speed and success in reaching its objective will improve its operations. It uses its own performance as a benchmark.
That same company might do a lot better if it compared its drilling performance with the best performances ever turned in for the same targets in the same geographical area. That new set of benchmarks lights the way to an even higher level of performance.

Aberdeen, Scotland's Rushmore Reviews, which conducts benchmarking of worldwide drilling and completions operations outside North America from 150 companies in 50 countries, recently conducted its third annual "Best Practices in the Benchmarking of Drilling and Completions" conference with some of the best benchmark experts in the oil and gas industry as participants and speakers.

Using benchmarks

"The benchmarking studies give us sufficient information to conduct important analysis and to shape our conversations with other operators on key issues," said Gabriel Higuera, drilling and completions performance specialist with BP in Aberdeen.

Helen Rushmore, director of Rushmore Reviews, said, "We are seeing a real and increasing determination among the operators to drive performance improvement using benchmarking data as a key tool."

Peter Rushmore said companies typically use benchmarking in four prime-focus areas:
• For budgeting and planning for wells in new areas;
• For target setting. Identify the best-in-class well for a category and aim to beat it;
• To identify the specific performance gaps between a client's company and the best in the field for quick wins; and
• To identify the best-in-class operators, study what they do differently and then adapt and adopt those best practices back home.

Objectives vary, he said. Shell's Drilling the Limit strives for perfection, but some Shell divisions use benchmarking to set "real-life" targets that drilling crews will buy into. BP's Beyond the Best and Great Operator programs use benchmarking to discover the best performance and use that as a spring board to match and beat. "Every BP well has a best-in-class well (normally drilled by another operator) tied to it," he added.

"The growth in the last decade in drilling and completions benchmarking has been impressive but looks like being just the start as even more operators worldwide look to this performance improvement methodology in their quest for the perfect well."

In the field

During the conference, Kimberly McHugh, global benchmarking coordinator for Unocal Corp., said her company had used benchmarking to help it slash drilling times for typical 11,700-ft (3,568-m) deviated wells in the Gulf of Thailand from almost 70 days to just 4 days since the 1980s.

"Dedicated management principles, above-and-beyond technological advances, favorable conditions and teamwork throughout the business unit have been the key to our success in Thailand," she said.

Colombia

BP used a combination of techniques to improve performance for its deep wells in complicated geology in Colombia's Llanos Basin, and it has been able to drive the time needed to drill from 188 days per 10,000 ft (3,050 m) down to 140 days per 10,000 ft, according to IADC/SPE paper 87120. Andrew Frazelle, Juan Francisco Sarmiento and Reynaldo Vargas with BP Exploration Co. Colombia and Jan Garoby and Raul Krasuk with Baker Hughes Oasis explained the process in the paper titled "Beyond-the-Best Initiatives Deliver Breakthrough Performance: Deep Exploration Well, Colombia."

In that Niscota exploration well, drilling the overthrusted fault, they faced borehole stability problems, abrasive formations, low progress rates, drill-string failures and hole deviation caused by faults and steeply dipping formations.

Benchmarking came in when the drilling team used a drilling optimization service to analyze the situation, including a review of drilling performance, mud logging and wireline data from reference wells.
That helped them identify the potential problems and set optimization objectives. It also helped them devise an action plan and find fit-for-purpose technologies to give them solutions.

It brought in the "technical limits process" that challenged operators and service companies to work as an integrated team and come up with best-in-class performance through trust and mutual respect among team members.

Even though the team set four world-record bit runs, it still is working on the potential for underbalanced, or near-balanced, drilling, increasing the well design flexibility, optimizing the casing program and custom-building a system to increase rate of penetration.

North Slope

ConocoPhillips has a history of efficient operations on the North Slope of Alaska, but it built on its existing technology and expertise to increase efficiency 17% on horizontal wells at its Alpine field. The company described the process in IADC/SPE paper 87176, "A Step Change in Drilling Efficiency: Applications of New Technology in the Alpine Development Field." Authors are Chip Alvord and Brian Noel with ConocoPhillips Alaska Inc.; Vern Johnson, Ron Handley, David Egedahl and Eric Gribbs with Sperry-Sun-Halliburton and Lee Smith with Security-DBS-Halliburton.

Environmental considerations were a big factor in the development of the field, since they held the pad size down to 97 acres, or 0.2% of the total field area. Well heads are only 10 ft (3 m) apart, and the Doyon Drilling Inc. rig can move from drill site to drill site under its own electric power.

After analyzing more than 1 million ft (305,000 m) of hole and drilling technology, ConocoPhillips expects to save an estimated US $4 million on the next 20 wells in the development series.

ConocoPhillips and the service company partners started with two steerable bottomhole (BHA) assemblies with a polycrystalline diamond compact (PDC) bit for the tangent section in the horizontal wells and a rock bit to land the curve. Now it uses a single point-the-bit rotary steerable system with an extended-gauge PDC bit on a steel body with an innovative nozzle/hydraulic system to prevent balling.
As a result, drilling performance has improved from 44 wells averaging 12,788 ft (3,900 m) per well drilling at a rate of 10,000 ft in 13.85 days in the first batch of wells to wells averaging 16,216 ft (4,945 m) drilled at a rate of 11.2 days per 10,000 ft.

Practice

Benchmarks are great for determining performance, and technology can't be beat for providing the tools that make holes straighter and drill them faster. A company can pre-plan the well and predict all the possible problems the drilling team will likely encounter, and it can set up contingency plans for any number of possibilities. But, those considerations are no substitute for experience.

Now, the oilpatch is trying to do next best thing on a drilling operation with the real-time information on the Drilltronics system.

Rolv Rommetveit, Knut S. Bjorkevoll, George W. Halsey and Hans Freddy Larsen with Rogaland Research; Antonio Merlo with Eni's exploration and production division; Leslie N. Nossaman an Miles N. Sweep with ChevronTexaco; Knut Martin Silseth with Statoil, and Sven Inge Odegaard with National Oilwell, explained the process in IADC/SPE paper 87124.

The paper, called "Drilltronics: An Integrated System for Real-Time Optimization of the Drilling Process," describes a new drilling automation and simulation system for drilling.

Although it's still under development, the system will be designed to present a mirror image of the real well, including downhole conditions and the interaction between those conditions and the drillstring and BHA.

If a pressure-while-drilling sensor in the well fails, for example, the simulation will be able to calculate the missing pressures at the sensor location as the drillstring continues to advance. The simulator automatically updates its information from the real data.
Automation includes such actions as automatic control of the drawworks based on surge and swab calculations and automatic detection to take first action after recognizing a symptom of a hole problem such as pack off or stuck pipe.

Statoil plans to put the test system to work on its Statfjord platform in the North Sea.
If it all works the way it is planned, it will provide earlier detection of unwanted events, improved drilling data and automation of critical subsystems.

With all these advances in benchmarking, tools and technology and simulation and automation systems, it's getting harder and harder to drill a bad well.

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