Operators and service companies have concentrated more resources on lowering the cost and raising the effectiveness of wells than any other area of operations. They have made tremendous progress, but they're a long way from satisfied.

That concentration of resources just makes sense. The drilling operation accounts for approximately 60% of the cost of all capital expenditures in upstream oil and gas, according to consultants James Miller & Co. Inc. of New Ulm, Texas, and the highest-cost item is the obvious target for savings.

Benchmarking is the first line of offense in the battle to control costs. If a company can learn the lowest cost for each drilling component by the most efficient companies in the field and match or beat those costs, it can come close to a near-perfect well.

Benchmarking

The Spring issue of "Gas Tips," published by the Gas Technology Institute, the US Department of Energy's National Energy Technology Laboratory (DOE/NETL) and Hart Energy Publishing LP featured an article titled, "Benchmarking Deep Drilling and Completion Technologies." Authors John D. Rogers of DOE/NETL, Stephen W. Lambert of Schlumberger DCS and Steve Wolhart of Pinnacle Technologies talked about a study designed for the Deep Trek program to benchmark drilling below 15,000 ft (4,575 m) in key US basins with the help of the IHS Energy database and Schlumberger Data Systems.

A part of that continuing study breaks out costs in key basins for borehole integrity, cementing, data generation and monitoring, drill bits, drilling and tripping time, environmental activities (including waste handling and regulatory requirements), wireline logging, people, safety, stimulation and tubulars. It detailed those measurements in terms of total well cost and the percentage of each cost to the whole well.
That article also illustrated the value of technology. A 1985 well in the United States took 185 days to drill and complete. A 2002 well drilled in the same area to the same target took 58 days to complete.
Activities

The areas that can be benchmarked, however, are only a piece of the equation that brings an operator closer to the perfect well. James Miller & Co. is putting together the findings of inquiries from numerous companies, including interviews with more than 300 professionals and managers and another 300 knowledge workers in the drilling chain. Representatives also talked with service company experts.
It has grouped drilling operations into four classes, organizationally linked, capital utilization, knowledge-based and operational activities.

Organizationally linked activities included the driller's culture, organization drag and organization structure. These activities cover the attitudes, mindsets, politics and bureaucracy that affect drilling activity.

Capital utilization activities include capital discipline, drilling business processes, drilling supply chains and hidden costs.

Knowledge-based activities cover asset teams, explicit and tacit knowledge, the aging workforce and leadership.

Operationally based activities encompass rig contractors, non-USA drilling, exploration performance and drilling vendor performance issues.

That study will form the basis of a series of articles that will appear in E&P magazine every other month, starting in February.

Knowledge

The spread of knowledge about the drilling operations to include as much expert advice as necessary has become a big piece of the drilling operation, particularly in complex offshore operations. SPE paper 90367, "Statoil's First Onshore Support Center: The Result of New Work Processes and Technology Developed to Exploit Real-Time Data," shows the importance operators place on fast, accurate data analysis during drilling.

Authors Andrew McCann, Svein Omdal, Runar K. Nyberg of Statoil ASA and Oyvind Mydland of StepChange AS, in a paper presented at the 2004 Annual Technical Conference and Exhibition, said the center provides data transfer and video-conferencing among rigs, platforms and vessels in the Halten/Nordland area, which includes Heidrun, Asgard, Norne and Kristin fields. Ideally, everyone involved in the well can make better decisions if they're all looking at the same real-time data from the drilling well, offset well log and drilling data, seismic data and geological and petrophysical information.

On the E-1 BH oil well in Heidrun field, the company wanted to drain a small horst, and it considered two well paths. Collaboration made possible in the support center and real-time log interpretation allowed optimal placement of the well and the recovery of up to 1.5 million bbl more than the 14.4 million bbl initially predicted.

At the same event, G. Robello Samuel and Glenn McColpin of Halliburton-Landmark Graphics presented SPE paper 90048, "Accelerating Drilling Technology with eKnowlege Factory: A Changing Paradigm."
That system sets up a procedure to capture drilling information and store it digitally in "buckets" designed to fit an individual company's work practices. Later, if someone in the company needs advice on a specific drilling practice, he or she can go to the proper digital bin and search for the information in the specific bucket. That practice should help companies mitigate knowledge erosion caused by the graying of the industry.

SPE paper 90659, titled "3D Visualisation: A Common Language for the Drilling and Subsurface Communities," by C. Telford and M. Burns with BP Exploration Ltd and N. Whitely with Landmark Graphics described the use of a 3-D pressure cube and 4-D seismic to find the best trajectory for wells in Andrew field in the North Sea.

It made two particularly telling points. First, visualization is only a picture. The information it displays encourages multidisciplinary teams to discuss aspects of the process and the effects of each discipline's impact on the other. Second, BP's "no drilling surprises" doesn't mean no drilling problems. "It means there should be no surprises when they do happen as they will have been identified, investigated and understood so mitigation plans and contingencies can be formulated and communicated."

Technique

An article prepared for Weatherford International's W magazine quoted a study called "A Probablistic Approach to Risk Assessment of Managed Pressure Drilling Offshore" prepared for the Drillling Engineering Association by O. Coker and K.P. Malloy that said up to 33% of all remaining undeveloped conventional reservoirs are not drillable using overbalanced drilling techniques. In the same article, a James K. Dodson study showed 9% of offshore well problems come from kicks, 3% from shallowwater flow, 13% from lost circulation, 3% from sloughing shale, 11% from stuck pipe and 3% from twist off. All of those problems could be avoided or mitigated by managed pressure drilling.

The service industry currently has a big push going to extend the proven onshore managed pressure drilling techniques to offshore provinces. They have been used in some parts of the world, but for full acceptance, they must be accepted in the Gulf of Mexico and the North Sea.

Speed

For some operators, a good well means a cheap well that delivers the goods. In drilling parlance, a cheap well is a fast well. That philosophy worked particularly well for Unocal in the Gulf of Thailand. The technique was described in IADC/SPE paper 87173, "Ultrafast Drilling in the Gulf of Thailand: Putting Science into the Design Process," by C.J. Pinto of Unocal Thailand Ltd.; Consultant L.E. Pendleton; and J.L. Dick, L.A. Sinor, J.Oldham and B. Stouffer with Hughes Christensen Co.

Unocal is a veteran operator in this part of the world, and its improvements have driven costs and drilling times down from US $10.9 million (in today's dollars) and 68 days for a typical well in 1980 to less than $950,000 in 5 days today.

In this case a new bit design called the Auger did the trick. The first run with the specifically designed bit resulted an 840 ft/hour (256 m/hour) through a 5,040-ft (1,537-m) section while building inclination from 26? to 56? before dropping back to 37? at total depth. In the process, the bit also made an azimuth turn from 305? to 358?.

The same design later averaged 1,023 ft/hour (312 m/hour) over a 6,144-ft (1,873-m) section with some rates of penetration exceeding 2,000 ft/hour (610 m/hour) through a 1,000-ft (305-m) section.
The new bit broke five Gulf of Thailand records.

Breakthroughs

When ExxonMobil couldn't find a 3-D rotary steerable system (3D RSS) that made economic sense on onshore wells, it created its own design on paper.

John T. (Tim) Travis Jr., Jeff H. Moss and Greg M. Browning at ExxonMobil Development Co. could justify the high cost of 3D RSS on high-cost wells reaching for big targets offshore. The onshore economics were tighter, they said in IADC/SPE paper 87165, "An Operators Targeted Development of Low-Cost 3D Rotary Steerable Systems." They needed a new solution.

An offshore spread cost for a well could run $100,000 to $500,000 a day, but an onshore well might run only $15,000 a day. Existing 3D RSS systems were so expensive that a lost-in-the-hole cost could exceed the entire authority for expenditure for the well.

They decided they didn't need logging while drilling for onshore applications, they didn't see 3D RSS as a formation evaluation tool. An, in this case, push-the-bit or point-the-bit technology was irrelevant.
They scheduled face-to-face meetings with service company representatives and asked two service companies to build special low-cost systems. Those new tools now are in field tests and results have matched expectations. Rate of penetration on land has increased up to 200%.

Everyone doesn't have the clout with service companies that ExxonMobil can wield, but a good new idea might work wonders for both the service company and the operator.

The key to approaching the perfect well is integration and coordination. Each member of an asset team working on a drilling project can supply useful information. If the company optimizes its work processes, and the people get the right tools and have the ability to acquire and interpret the information they need, then the process can work wonders.

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