Author: John Cochener, john.cochener@eia.doe.gov, (202) 586-9882

Disclaimer: Views not necessarily those of the U.S. Energy Information Administration

Quantifying Drilling Efficiency

John Cochener

Office of Integrated Analysis and Forecasting

U.S. Energy Information Administration

Initial Release: June 28, 2010

This paper is released to encourage discussion and critical comment. The 

analysis and conclusions expressed here are those of the author and not 

necessarily those of the U. S. Energy Information Administration.
Author: John Cochener, john.cochener@eia.doe.gov, (202) 586-9882

Disclaimer: Views not necessarily those of the U.S. Energy Information Administration

Quantifying Drilling Efficiency

Abstract

This paper examines the methods used to measure drilling efficiency and the difficulties 

encountered when using various data sources. The analysis examines the technologies 

used before, during, and after rotary rig operation which shape overall productivity 

results. The research also reviews the reasons why modern rigs are more efficient and 

where the industry is headed in the future. Finally, the paper provides guidance for 

analysts and modelers when applying efficiency parameters.

Background

Many analysts attribute recent increases in domestic oil and gas supply1, 2, 3 to improved 

drilling efficiency. Efficiency is defined as a metric of productive output for a given a set 

of inputs. This paper discusses how drilling efficiency is measured, the difficulties and 

ambiguities associated with productivity measures, and the technologies that have 

improved drilling efficiency. The analysis focuses on the operational factors shaping 

efficiency and is not a review of drilling costs. Reduced drilling costs are one of the 

implications of improved efficiency.

Prior to the 1990s, most wells were drilled vertically. Since then, more and more wells 

are being drilled horizontally, particularly the highly-publicized shale wells. Horizontal 

wells have risen from about 9 percent of total wells drilled in the early 1990s to over 50 

percent in 2010. This trend has advanced to the point where one natural gas service 

provider4 has introduced a proprietary index to adjust the rig count for efficiency gains to 

better predict future natural gas production. The traditional ways of viewing drilling 

efficiency are changing. 

Drilling is a 3-step process. Operation of the physical drilling rig represents the middle 

step. Of equal or greater importance in the process are activities and decisions 

immediately preceding and following rotary rig operation. The drilling rig by itself does 

not cause either successful well outcomes or dry holes. Successful outcomes arise from 

the synergies between rig activity and the augmenting steps. 

Traditional Methods for Assessing Drilling Productivity

Measuring and quantifying the factors shaping drilling performance is difficult due to the 

availability of timely data, some of which is proprietary. Numerous factors impacting 

performance can vary from location to location and from rig to rig. Also, aggregate 

drilling data is problematic due to the range of information collected that may combine 

 1 “U.S. crude oil production rose 7.4% last year, energy report says,” PennEnergy, 

http://www.pennenergy.com/index/articles/newsdisplay/142979329.html. 2 “U.S. Natural Gas Reserves May Have Doubled, Secretary Chu Says,” Bloomberg, April 6, 

2010, http://www.businessweek.com/news/2010-04-06/u-s-natural-gas-reserves-may-havedoubled-secretary-chu-says.html. 3 “U.S. natural gas production reaches highest level in 30 years,” Star-Telegram, May 28, 2010. 

http://www.star-telegram.com/2010/05/28/2225254/us-natural-gas-production-reaches.html. 4 “A New Era in Rig Productivity,” Bentek, http://www.bentekenergy.com/BPI.aspx.
Author: John Cochener, john.cochener@eia.doe.gov, (202) 586-9882

Disclaimer: Views not necessarily those of the U.S. Energy Information Administration

disparate regions such as the offshore with onshore regions. Data typically lags and the 

use of aggregated data can mask emerging trends.

Efficiency measures can cover time, distance, performance, productivity, and financial 

parameters including:

• Footage drilled per hour

• Days to depth (drilling days)

• Footage drilled per rig

• Wells drilled per rig

• Success rates (or dry holes)

• Reserves added per well

• Reserves added per rig

• Production per well

• Dollars per foot

• Energy consumption

One common measure of drilling efficiency is the ratio between annual footage drilled 

and the number of “active” rigs. This is the total footage drilled yearly for oil wells, gas 

wells, and dry holes divided by the number of active rigs operating during a study year. 

However, results depend on establishing a representative “active” annual rig count 

which is an imprecise and subjective task. Baker Hughes,5 Smith,6 ReedHycalog (Now 

NOV),

7 Schlumberger,8

and IADC9 publicly report the number of active and available rigs 

with supporting details covering drilling applications, depth capabilities, power ratings, 

etc. For the ReedHycalog census, data is not available for 1953, 1954, and 2002 due to 

extenuating business circumstances and the analyst must use judgment in estimating 

the missing data points. For services type operations such as work-overs, the Cameron 

web site provides the Guiberson-AESC Service Rig count.10 Each organization has its 

own criteria establishing when and how to count a rig’s reported status as active,

available, moving, performing work-over, stacked, retired, the intended drilling trajectory 

(vertical, directional, horizontal), etc. For example, Baker Hughes defines a rig “at work” 

until it reaches its target depth while Schlumberger includes related operations such as 

logging, cementing, running casing, well testing, etc. 

Figure 1 presents the annual average footage drilled per rig (blue bars) and the 

corresponding rig utilization rate (red line) using data from the EIA Annual Energy 

Review 2008 and National Oilwell Varco (NOV), respectively. The average footage 

drilled per rig has nearly doubled from 100,000 feet per rig in the early 1980s to over 

200,000 feet by 2008, the last year for which corresponding footage and rig count data is 

available. The total drilled footage includes oil wells, gas wells, and dry holes. While 

Figure 1 represents an industry average, individual rig footage per year can vary 

 5 Baker Hughes Investor Relations, Rig Counts, Rig Count FAQs, 

http://investor.shareholder.com/bhi/rig_counts/rc_index.cfm. 6 Smith, Rig Activity, http://www.smith.com/$53722c42-5095-45af-b97b-e8c6dd035e60. 7 NOV Downhole, 56th Annual Rig Census, http://www.nov.com/. 8 Schlumberger Worldwide Rig Count, 

http://www.apps.slb.com/rigcount/World/Country/Default.aspx. 9 International Association of Drilling Contractors (IADC), Statistics on IADC Membership and the 

Worldwide Rig Fleet, page 22 of 2010 Membership Directory.

10 Guiberson-AESC Service Rig Count, http://www.c-a-m.com/content/dps/drl/rigcount/index.cfm.
Author: John Cochener, john.cochener@eia.doe.gov, (202) 586-9882

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considerably. The Land Rig Newsletter

11 conducted a survey of the top 75 drilling rigs 

operating in 2004 and found that the top rig drilled over 461,000 feet while the 75th place 

rig drilled over 221,000 feet that year, which is considerably higher than the 155,000 foot 

average for the nearly 1,200 rigs covered by the survey. 

Figure 1. Total Annual Footage Drilled Per Rig (Oil, Gas, Dry Holes) Shows Long-Term 

Progress; utilization rate shows an inverse correlation to footage drilled

Such rig drilling footage variation exists partly due to the total time the bit was “turning to 

the right” and because more-experienced crews and higher-spec rigs perform

significantly better than the average results depicted. Conversely, during periods of 

peak rig demand and utilization (e.g., the early 1970s through the early 1980s), older 

rigs and less experienced labor reduced overall efficiency. Not surprisingly, efficiency 

typically increases when the least efficient rigs are stacked (low utilization rate). There 

appears to be a loose inverse relationship between high utilization rates and lower 

footage rates. 

Other causes for the year-to-year variation in footage include the rock hardness of the 

geologic formations being drilled, whether the footage drilled is vertical or horizontal, and 

the type of drill bit being used. Prevailing oil and gas prices also tend to encourage or 

discourage drilling activity. 

Ranking performance on a footage basis often favors rigs drilling shallower wells since 

the rate of penetration is higher in shallower depths. Depending on depth, a rig can

frequently complete a well before the drill bit wears out and requires time for 

 11 “Most Active Individual Land Rigs, 2004,” The Land Rig Newsletter, Vol 27, No. 2, February 28, 

2005. 

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Author: John Cochener, john.cochener@eia.doe.gov, (202) 586-9882

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replacement. Drilling time also increases geometrically with well depth confounding 

interpretation of drilling efficiency between wells. Over time, well footage can expand or 

contract depending on attractiveness of oil and gas prices, so historical point 

comparisons may not necessarily be valid over a long term.

Figure 2 presents the number of wells drilled annually per rig and is derived from well 

and rig counts reported in the EIA Annual Energy Review 2008. Although the overall 

trend is up, there have been periods of declining performance as illustrated here and in 

the footage-drilled chart (Figure 1) presented earlier. The recent plateau around a 30-

wells per rig level since the mid-1990s might be attributed to deeper wells and wells 

having longer and/or more laterals in recent years. 

Figure 2. Annual Wells Drilled per Rig Illustrate a Plateau in Recent Years

Other than using aggregate industry rig counts, there are other time-based measures to 

gauge drilling efficiency when applied to a single rig. These measures include: Spud-toRig-Release; Spud-to-Spud (between wells); Spud-to-Sales; Footage per Day; Footage 

per Rig, Rig-Days, and Rotating-Hours.12 Closely related to the footage per day metric 

is Rate of Penetration (ROP) which is used by drillers as a gauge of progress while 

performing a job. All these measures are highly project specific, site specific, and cover 

a limited time duration. 

There are recent examples for the Fayetteville and Haynesville shales illustrating 

industry application of these metrics. For Southwestern Energy, in the Fayetteville shale, 

field time required to drill a well dropped from 20 days in first quarter 2007 to 11 days by 

 12 Janwadkar, Sandeep, “Keys to Unconventional Success,” Baker Hughes, January 7, 2009, 

http://files.shareholder.com/downloads/BHI/692977774x0x270440/070471f4-3d63-4fea-bf39-

08c06c56712f/UBS_Unconventional.pdf.

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the second quarter of 2009.13 This improvement enabled the number of wells drilled per 

rig to increase from 18 to 33. Likewise, Petrohawk Energy Corporation decreased 

drilling days in the Haynesville shale from 69 days in the first quarter of 2009 to 52 days 

by the fourth quarter of 2009.14 One theory is that gains of this nature are the result of a 

short-term “learning curve” at the company or play level rather than an efficiency trend 

across industry due to technology. 

As these examples illustrate, wells drilled per rig is a key performance metric used by 

producers and rig contractors drilling the same type of well in a given field.

Figure 3 shows the experience of EXCO Resources in the Haynesville shale over time 

and graphically illustrates a progression of improving efficiency in drilling days (days to 

depth). Notice how a steepening penetration curve decreases the number of drilling 

days required. For a given shale play, the drilling days range seems to be converging. 

The use of contract drillers is the likely mechanism through which “learning” is spread.

However, not all shales are the same and result in a different level of drilling days. 

Some, such as the Haynesville, require almost twice the hydraulic horsepower due to 

increased depth, harder rock, higher temperatures, and necessitate higher treating 

pressures and more advanced fluid chemistry than the Barnett and Woodford shales.

15

Figure 3. Haynesville Horizontal Drilling Days (Days vs Depth) Shows Productivity Gains

Source: Data courtesy of EXCO Resources, Investor Presentation (December 2009), Slide 29.

 13 Southwestern Energy Company, Q2 2009 Earnings Call Transcript, July 31, 2009, 

http://seekingalpha.com/article/152977-southwestern-energy-co-q2-2009-earnings-call-transcript. 14 Petrohawk Energy Corporation Presentation, Howard Weil 38th Annual Energy Conference, 

March 23, 2010, Slide 15, http://www.petrohawk.com/ir/presentations-events.aspx. 15 “U.S. Shale Gas; An Unconventional Resource. Unconventional Challenges,” White Paper, 

2008, Halliburton, page 4, http://www.halliburton.com/ps/default.aspx?navid=1413&pageid=2867.

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Behind-the-Scenes Preparation Work

Often overlooked in the overall drilling process is the necessary preparatory work to 

guide drilling to a successful conclusion. A particular gauge of drilling efficiency (and 

success rates) is minimizing the number of dry holes incurred. There are two common 

metrics for determining a dry hole percentage: (1) the ratio between dry holes counted 

to the total wells drilled, or (2) the ratio of footage comprising dry holes to the total 

footage drilled. Both measures yield similar results as shown in Figure 4. Success 

rates, in turn, relate directly to the reserves added per well and indirectly to the reserves 

the rig is credited with adding.

Figure 4. Dry Holes (Footage and Well Count Basis) Show Parallel Trends

The “dry hole” metric has dropped from a level of over 40 percent in the 1960s to about 

10 percent today. Much of the reduction is attributed to improved exploratory techniques

from knowledge gained with 2-D and 3-D seismic and other emerging monitoring and 

analysis tools. A “dry hole” well in some cases is not necessarily due to a lack of 

hydrocarbons but is one that can’t produce sufficient hydrocarbons to be commercially 

profitable. With the advent of shale drilling in recent years, riskier wildcat drilling is being 

replaced with more certain “exploratory” situations where the existence of hydrocarbons 

is already known. Some say that shale drilling is now more akin to a manufacturing 

process wherein wells are drilled and completed with assembly line repetition.

Technology, such as rotary steerable systems (RSS),16

 16 Bryan, Cox, Blackwell, Slayden, Naganathan, “High Dogleg Rotary Steerable System: A Step 

Change in Drilling Process,” Society of Petroleum Engineers, 2009, SPE paper 124498.

has been the catalyst for 

improved accuracy allowing drillers to better home in on their target the first time.

Another emerging support technology is the use of satellite data to show oil field thermal 

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Author: John Cochener, john.cochener@eia.doe.gov, (202) 586-9882

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anomalies to pick attractive spots for drilling.17 These and similar tools allow drillers to 

precisely orient well bores in reservoir “sweet” spots. Microseismic technology18 allows 

drillers to place horizontal laterals perpendicular to the natural fractures in a formation to 

maximize production.

Another possible performance metric is reserve additions per active drilling rig as 

illustrated in Figure 5. One would expect that technology advancement would result in 

positive sloping performance curves over time. However, a number of seemingly 

contradictory long-term and short-term trends are in operation for both oil and gas. The 

natural gas curve shows a gradual long-term decline, which contradicts recent reports of 

increasing gas reserves and success in the shales. On an industry aggregate level, this 

measure is difficult to interpret due to the mix of diverse reserve additions added through 

the drill bit in exploratory mode, field extension mode, and reserve revisions booked as a 

result of outside factors including price changes. A few delineation wells in a field can

also affect the statistics influencing reserve additions per well. In-fill drilling and 

uncompleted wells also cloud data trends between adjacent years. 

Curiously, the crude oil curve in Figure 5 exhibits both up and down trends. The 2001 

peak is likely to arise from contribution of early deepwater offshore drilling performance. 

Figure 5. Multiple Reserve Addition Trends Within Aggregated Data

 17 Gupta, Ravi P., Chakraborty, Rupam, Awasthi, Arnun K., “Satellite data can cost effectively 

show oil field anomalies,” Oil & Gas Journal, November 2, 2009, http://www.ogj.com/index/articledisplay/4237979508/articles/oil-gas-journal/volume107/Issue_41/Exploration___Development/Satellite_data_can_cost_effectively_show_oil_field_th

ermal_anomalies.html. 18 “Going live with microseismic downhole monitoring,” Engineer Live, 

http://www.engineerlive.com/HydrographicSeismic/4D_Fixed_Installation_Seismic/Going_live_with_microseismic_downhole_monitoring/207

98/.

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Also possibly influencing this outcome is a tendency for larger fields to be discovered 

first which contributes to positive additions. As the remaining smaller fields have 

subsequently been discovered since 2001, this has resulted in a series of declining 

contribution to oil reserve additions. Also occurring after 2001 has been a general 

increase in the total footage drilled, the rig utilization rate, and the number of oil and gas 

wells drilled.

These factors imply that reserve additions are more closely aligned with well counts than 

the number of rigs that happened to be utilized to drill the wells. Thus, factors removed 

from the control of drilling rigs actually shape reserve additions.

Given the limitations of aggregate data, focusing on particular play areas can lessen 

statistical “noise” but not completely eliminate it. Three well-known shale plays include 

the Barnett, Haynesville, and Marcellus. As a proxy for these 3 shales, one can use 

industry data for Texas Railroad Districts 5 & 6, North Louisiana, and Pennsylvania for 

reserve additions and associated rig counts to collectively calculate reserve additions 

per rig for these combined regions as shown in Figure 6. The regional reserve additions 

are from EIA Natural Gas Navigator data while the rig count is from Hughes-Christensen 

(Baker Hughes). Of interest to the analyst or modeler, since 1995 the overall Billion 

Cubic Feet (Bcf) added per rig has increased, but with a decline in the last several years. 

Despite being more narrowly focused, the localized data shown in Figure 7 also contains 

vertical wells, recompletions, and workovers which distort the desired horizontal-only 

drilling impacts. It should also be noted that the Barnett shale has included an 

increasing quantity of “non-core” area drilling over time which are contributing to 

diminishing returns and a weakening of the composite proxy curve.

Figure 6. Gas Reserve Additions per Rig in Barnett, Haynesville, and Marcellus Plays 

Key shale plays: Tx RRD 5 & 6, North Louisiana, Pennsylvania.

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Why Modern Drilling Rigs Are More Efficient 

Improved efficiency can be achieved through the effective management of effort to 

improve productivity. The old adage “time is money” applies here with results showing 

up as lower drilling costs per foot and cost per well. Drillers and producers rely on five 

basic strategies to increase productivity and lower costs: (1) Minimizing Non-Productive 

Time (NPT), (2) Working Faster, (3) Working Smarter, (4) Making Better Decisions, and 

(5) Tailoring Rig Design for Purpose. The strategies are inter-related and highlighted 

below:

(1) Minimizing Non-Productive Time (NPT)- The basic concept is for the rig to spend 

more time working and less time waiting. In the drilling business, waiting time is 

nonproductive time. Reducing NPT is addressed through rig design and efficient work 

practices. One way for a rig to minimize NPT is to spend more time drilling and less time 

in transit. For the drilling rig itself, NPT is time the drill bit is not “turning to the right.” 

Once drilling is finished, the cycle begins again on the way to the next location. 

Rigs are now being designed to disassemble, move 100 miles, and rig up in 48-hours.19 

Another concept is moving rigs by sliding20 on a drilling pad, in which well-to-well rig 

moves are possible in less than 2 hours. New rigs are designed with fewer and simpler 

electrical connections to facilitate rig up and rig down. Design features often involve 

reduced weight components and safety rails that fold for faster rig moves between sites. 

Other time and cost savers include rigs designed for assembling at ground level to avoid 

the use of a crane.

In drilling mode, NPT includes pulling out of the hole to change drill bits, inserting 

additional joints of drill pipe, and conducting logging operations to evaluate progress. 

One technology to partially avoid these issues is thru-the-bit-logging which avoids the 

time required to pull the drill string.

(2) Working Faster- Rig time is one of the more expensive aspects of drilling costs. 

The drill bit is the single equipment component most impacting the rate at which a well 

progresses to total depth (TD). The holy grail of drilling metrics is Rate of Penetration 

(ROP). ROP is simply a measure of how fast a rig is drilling the hole. The measurement 

parameter is rate over time -- feet drilled per time unit, whether expressed in hours or

days. Higher penetration rates imply quicker drilling progress and less time (and cost) 

being consumed. The top performing bits drill faster and farther. Use of synthetic fluids 

in drilling muds also improves bit penetration.21 The drilling mud provides a conduit for 

removing the cuttings developed by shearing rock into a hole. Another time-saving 

strategy involves well design utilizing smaller bore holes enabling drilling smaller 

diameter holes with smaller drill bits.

The factor most affecting ROP is the physical characteristics of the rock (lithology) at 

various depths. Changing lithologies at various depths also create a set of variables that

 19 Global Energy Services, Product Brochure, 

http://www.glb-energy.com/pdf/GES%20Brochure%20TM%204-28pm_v9.pdf. 20 “Land rig technology advances,” Hart E&P, February 1, 2007. 

http://www.epmag.com/archives/features/240.htm. 21 Sparkes, Dan; Lee, Burney, “Synthetic fluid increases ROP by as much as 117%,” Drilling 

Contractor, May/June 2004.
Author: John Cochener, john.cochener@eia.doe.gov, (202) 586-9882

Disclaimer: Views not necessarily those of the U.S. Energy Information Administration

affect bit durability. Other factors influencing ROP and durability include mud condition,

weight on the bit (WOB), and rotary speed (RPM) of the bit. 

Traditionally there is an inverse relationship between ROP and durability; that is, higher 

penetration rates result in less durability while greater durability occurs at a cost of lower

ROP. Improved bit life determines how often a bit must be changed and often eliminates 

the incremental bit trip, and resultant delays and lost time.

The manner in which a drill bit is run (speed and loading) can have more effect on 

drilling performance than the particular bit design selected. Drilling rates may vary 

between two wells using identical bits. Drilling hazards can trigger unproductive time 

and include situations such as unexpected high or low penetration, excessive bit wear, 

elliptical hole, collapsing hole, fluid loss, fracturing the formation, blowouts, stuck pipe, 

collapsed casing, or junk in the hole. Drilling cannot be rushed since careless haste can 

cause time-wasting consequences. A particular challenge is protecting the formation 

without destroying it. This involves optimizing WOB and RPM settings to yield the best 

penetration rate. Fewer drilling days are the result of better bit design and increased 

hydraulic horsepower (HHP). Drilling challenges are overcome with improved drill bit 

technology.

22 

(3) Working Smarter- These strategies cover sequential activities, parallel operations, 

and utilizing technology to monitor progress and avoid problems. One management 

strategy is focusing on the best-perceived wells and high-grading rig crews. 

A particular approach is the “mixed fleet”

23 concept whereby contractors capitalize on 

the strengths of different types of drilling rigs performing in sequence. A lightweight 

hydraulic top-drive arrives first on a site and drills conductor holes and presets casing. 

Then a larger, more-robust rig drills the deeper segment of the hole. Each rig does what 

it does best to reduce time and cost. Still another concept, based on parallel operations,

is a rig designed with multiple well centers and fitted with movable function-specific 

tools.24

One efficiency strategy is identifying “sweet spots” by utilizing measurement-whiledrilling (MWD), logging while drilling (LWD), and through-the-bit-logging (TBL) 

technology to gather data and foresee problems that may be unfolding. Better data 

helps make better decisions. It is not so much the technology itself but the selection of 

applicable technologies and combinations of technologies that increase the likelihood of 

successful outcomes.

(4) Making Better Decisions- Management and planning decisions have significant 

impacts on the metrics contributing to improved efficiencies. One fundamental decision 

involves pad drilling where a number of separate wells are drilled from the same location

(pad). This reduces rig travel and set-up time and increases efficiencies by enabling rigs 

 22 “New Drill Bit Technology – The Deep Trek Program,” National Driller, November 1, 2006, http://www.nationaldriller.com/Articles/Feature_Article/c3fd796fd00ae010VgnVCM100000f932a8c

0.

23 “Mixed Fleet: A New Approach to Making Money in the Oil & Gas Market,” Atlas Copco. 24 Springett, Frank, National Oilwell Varco, “Driven by ‘crisis,’ rig design based on parallel 

operations, aims to change drilling process,” Drilling Contractor, May 17, 2009, 

http://drillingcontractor.org/new-concept-land-rig-design-based-on-parallel-operations-2661.
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Disclaimer: Views not necessarily those of the U.S. Energy Information Administration

to work in a single specific area and avoids the time and cost of clearing land and 

building roads. Other decision points involve making the proper choice in selecting 

correct motors and bits to drill the curve and the well lateral.

An additional but lesser utilized strategy is the use of multi-lateral drilling -- drilling

multiple horizontal laterals from one vertical wellbore. Still another technique is drilling

new laterals from existing wells. The length, number, and layout of laterals have a 

profound influence on production and economics. Pinnate drilling is a form of multilateral horizontal drilling in which a number of multi-lateral horizontal wells are drilled in a 

pattern similar to the veins on a leaf. Once completed, all the laterals produce into a 

single vertical borehole. Another highly-specialized layout is having 3 or 4 parallel 

laterals all originating at the same vertical wellbore, like tines on a fork. The potential for 

new laterals in existing well bores adds reserves and production but makes well-count 

data confusing for the energy analyst.

(5) Tailoring Rig Design for Purpose- Moving beyond traditional drilling activities has 

created a demand for higher spec rigs including special fit-for-purpose rigs specifically 

designed for targeted shale plays, horizontal drilling, and also suited for pad-site drilling. 

New rig technology incorporates AC induction motors (adopted from the offshore) which 

are efficient and quiet. AC motors are brushless, implying less maintenance, and are 

more suited for hazardous locations. AC motors also provide accurate speed and torque 

control and have the advantage of sustaining full torque at zero speed and supplying

maximum rated horsepower over a range of turning speeds compared to older DC 

motors where power varies with speed. Another technology includes Programmable 

Logic Control (PLC) which is a small, highly specialized digital computer that improves

motor and fuel efficiency and enhances power distribution. This enables greater control 

of drilling torque and ROP resulting in faster and better holes.

Rig technology development has always focused on minimizing the use of manual labor

on a drilling rig. Automated pipe handling systems have been a fixture on offshore rigs 

for years, and this technology is now being adopted to land rigs. In addition to time 

savings, the use of automated iron roughnecks (for connecting and disconnecting drill 

pipe) and booms to move pipe onto the rig floor also have the added benefit of 

increasing safety and reducing lost-time accidents. 

The need to handle casing determines the size and specifications of a rig’s mast, 

substructure, and draw works. Some drillers are using rigs with extended mast height to 

utilize longer drill pipe (45’ versus 30’) to avoid needing to stop drilling to add joints to the 

drill string, which adds up over the duration of a well. Fewer drilling pipe connections 

avoid this unproductive time. Being able to insert drill pipe faster is intended to reduce 

time (and costs). In Alaska, BP is utilizing a state-of-the-art rig in the Liberty field that is 

240 feet tall, enabling it to handle three jointed 90-foot pipe lengths when raising or 

lowering drill pipe string into the hole for changing drill bits or instruments.25 Coiled 

tubing drilling is also popular for relatively shallow wells because it avoids having to add 

and subtract pipe segments when changing drill bits or instruments.

 25 “BP to start Liberty drilling soon,” Trading Markets, April 11, 2010, 

http://www.tradingmarkets.com/news/stock-alert/pkd_bp-to-start-liberty-drilling-soon-903849.html.
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Well Completion is the Final Step in the Drilling Process

A newly drilled well has no utility (production or payback) until it is completed. Well 

completion is the process of preparing a well for production through perforation, 

fracturing, or stimulation activities along with the system of tubulars, packers, pumps, 

etc. installed under the wellhead. In a shale or tight sands well, the completion process 

generally costs as much, if not more, than the physical rotary drilling. The completion 

step presents an additional opportunity to optimize production economics.

Producers can optimize potential well production by drilling longer laterals, which means

more reservoir pay is in contact with the lateral. However, longer laterals increase the 

risk of a time-consuming mistake if something should go wrong during the drilling or 

fracing process. A related technique is closer lateral spacing between adjacent wells. 

The most widely utilized technique for better productivity is increasing the number of frac 

stages per well.

Figure 7. Lateral Lengths and Initial Production Rates Correlate 

Note: Production decrease in the first quarter of 2009 was due to pipeline constraint.

Source: Southwest Energy Investor Presentation, Slide 12, Fayetteville Shale.

Figure 7 contains data from Southwestern Energy Company showing average lateral 

length and Initial Production (IP) rates for the Fayetteville shale.26

 26 Southwestern Energy Company Investor Presentation, Slide 12, April 2010, 

 Lateral lengths 

increased from just over 2,000 feet in early 2007 to over 4,000 feet by late 2009. These 

longer completions allowed IP rates to increase from 1.3 billion cubic feet per day (Bcf/d) 

to 3.8 Bcf/d in the same time period. As information, the dip in first quarter 2009 

production shown on the graph was due to temporary pipeline take-away constraints 

which have since been remedied. 

http://www.swn.com/operations/pages/fayettevilleshale.aspx.

0

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Lateral Length (Feet) Initial Production Rate (Thousand Cubic Feet per Day)
Author: John Cochener, john.cochener@eia.doe.gov, (202) 586-9882

Disclaimer: Views not necessarily those of the U.S. Energy Information Administration

Petrohawk Energy Corporation is experimenting with new well designs in the Haynesville 

shale to reduce surface treating pressures from 15,000 pounds per square inch (PSI) to 

10,000 PSI which not only reduce well costs by the reduced compressor horsepower 

needed for well fracing, but opens up a larger pool of service providers resulting in more 

competitive bids.27

The secret to success in gas shales is keeping fractures open more effectively. One

Haynesville operator, Cabot Oil & Gas Corporation, keeps its wells pinched back during 

flowback. While this practice might not generate impressive IP rates, Cabot postulates 

that flowing wells back gently will keep sand in place and ensure that the formation won’t 

collapse around the wellbore and will boost potential estimated ultimate recovery (EUR) 

rates. A gentle flowback operating condition is good engineering practice that has been 

used for decades not only for limiting sand production, but also for reducing migrating 

fines, which is critical in low perm formations. This practice also has the potential to 

defer costly compression in later years which in turn avoids adding to operating costs. 

Apache Canada Ltd has applied microseismic to aid in frac work in real time in the Horn 

River basin. Apache used data to experiment with how different perforation patterns 

affected fracture propagation. In one instance the data showed an absence of growing 

microseismic activity which alerted Apache to switch from pumping proppant to flushing

a well with water to avoid a costly sanding of the fractures.28 The technology allows 

Apache to optimize the spacing of horizontal wells on future drilling pads.

The Future: How Efficiency Gains May Compound

Future advances in drilling and completion will build upon recent innovations. While the 

law of diminishing returns always remains in effect and presents challenges, gains are 

still available to be achieved as mechanical and electrical components are slowly 

upgraded over time resulting in a higher-performance rig. The next game-changing 

transition is a swing to horizontal drilling for oil in shales.

Drilling efficiency will steadily improve as old rigs are retired and new rigs enter the work 

force. A drilling rig can be expected to last 20-25 years depending on utilization, 

maintenance, and applications. Also, drilling contractors continuously upgrade individual 

rig components as equipment wears out and is replaced. Upgrades typically include 

increased horsepower, top drives, automated equipment, etc. Presently, only a very 

small percentage of land rigs have automated pipe rackers. Likewise, just 14% of the 

U.S. fleet is AC-driven new builds.29 This leaves considerable room for additional 

improvement to upgrade rigs as business conditions permit. 

Repowering rigs with new advanced diesel engines is a popular upgrade and enables 

gaining additional horsepower (hp) and achieving fuel savings which can be on the order 

of 10 to 20-plus percent. New equipment also has the obvious additional advantages of 

reductions in maintenance, repairs, downtime and emissions. The new power gives the 

 27 Natural Gas Week, May 31, 2010, page 18. 28 “Microseismic aids Horn River frac work,” OGJ, May 19, 2010, http://www.ogj.com/index/articledisplay/0665176246/articles/oil-gas-journal/drilling-production-2/productionoperations/ior_eor/2010/05/microseismic-aids/QP129867/cmpid=EnlDailyMay202010.html. 29 Rach, Nina M., “Reinvesting will pay off,” Harts E&P, February 2010, page 31.
Author: John Cochener, john.cochener@eia.doe.gov, (202) 586-9882

Disclaimer: Views not necessarily those of the U.S. Energy Information Administration

rig contractor a competitive advantage when bidding against other rigs without the fuel, 

horsepower, and maintenance advantages. A good example of this practice is Big E 

Drilling which found that a new 1,500-hp rig was using the same or less fuel than an

older 1,000-hp rig.30

As recently as 2 years ago, the U.S. had about 2,000 actively working rigs, implying a 

500 rig surplus at the current 1,500-level rig count. Many of these stacked rigs are 

candidates for efficiency modifications in an improving producer price setting. A 

favorable product price environment could also spur a wave of new purchases such as 

last occurred in 2004-2006 and would result in more upper-end rigs becoming available. 

Another area for continued improvement is a reduction in time for moving rigs between 

locations. Look for more rigs to incorporate modular designs to minimize move time.31 

A more radical concept is the idea of “walking rigs” which would move by themselves to 

new drilling locations.32 The “walking” rig has the ability to walk in any direction and turn 

360 degrees. It is capable of walking 15’ in two hours with 12,000’ of pipe in the 

derrick.33

A Norwegian company, Seabed Rig, has revealed plans to develop a completely 

automated offshore exploratory rig that would operate under water and without a crew. 

A prototype rig has been constructed and will be demonstrated by December 2010.34 All 

rig operating functions would be remotely controlled from a room on a surface vessel or 

on land.

The offshore remains a sizeable exploratory frontier given that most of the waters have 

yet to see extensive activity and long lead times limit the amount of progress short term. 

The offshore will continue to be a ‘laboratory’ and showcase where pioneering

technologies are first developed and which will later find applications in onshore plays. 

Towards the middle of this century, futuristic ideas such laser drilling could materialize. 

Laser drilling could dramatically reduce drilling times to a matter of hours per well. The 

application of lasers has been contemplated for at least a decade but considerable R&D 

still needs to occur.35

 30 “Big E Drilling repowers two of its land rigs,” Drilling Contractor, January/February 2001, 

 An additional advantage of laser drilling is that the beam melts the 

rock formation and creates a “self-casing” channel which also has further potential to 

reduce well completion time for shallower wells. Limitations of laser drilling are high

power requirements and needed innovations to “turn corners” for horizontal drilling 

applications. A safety concern yet to be resolved is how to avoid igniting gas pockets 

encountered during the process.

http://www.iadc.org/dcpi/dc-janfeb01/j-bige.pdf. 31 Moritis, Guntis, “Special Report: Unconventional basins require new rig types,” Oil & Gas 

Journal, February 1, 2010, http://www.ogj.com/index/article-display/6482137726/articles/oil-gasjournal/volume-108/issue-4/technology/special-report__unconventional.html. 32 “Walk baby, walk: New rig drills, then moves.” Houston Chronicle, March 12, 2010. 

http://www.chron.com/disp/story.mpl/business/6911337.html. 33 Range Resources Corporation, Custom Built Rigs (Apex Series Rigs), Howard Weil 38th

Annual Energy Conference, March 23, 2010, Slide 43.

34 “In Disaster’s Shadow, Norwegian Firm Unveils Fully Automated Rig,” Natural Gas Week, May 

17, 2010, page 4.

35 “Laser Oil and Gas Well Drilling,” Argonne National Laboratory, U.S. Department of Energy, 

http://www.ne.anl.gov/facilities/lal/laser_drilling.html.
Author: John Cochener, john.cochener@eia.doe.gov, (202) 586-9882

Disclaimer: Views not necessarily those of the U.S. Energy Information Administration

Guidance for Analysts and Modelers

Over the last 60 years, the drilling industry has demonstrated an ability to increase 

annual footage drilled per rig despite the ups and downs of the market. This uptrend is 

expected to continue with technological innovation being the enabling mechanism. 

Factors shaping adoption include R&D lead times, market penetration rates, market 

acceptance, and affordability by market players. One “headwind” working against an 

uptrend is resource depletion, implying deeper drilling requirements and smaller field 

sizes, resulting in less reserve additions per active rig even though footage drilled per rig 

may be increasing.

Aggregate industry annual data is too cloudy for applying accurate drilling efficiency 

assumptions. For the analyst projecting short-term play-level production gains, wells 

drilled per rig is the soundest modeling methodology to establish a well count. Similarly, 

for projecting reserve additions and future production, reserve additions per well is a 

more precise technique than using reserve additions per rig. As previously postulated, 

there is one degree of separation between a rig and a well and two or more degrees of 

separation between a rig and reserves. 

The analyst and modeler should be alert to an emerging trend towards smaller choke 

sizes and other design changes in horizontal wells for impacts these new practices can 

have on IP rates and slower aggregate decline curves. 

Lessons learned in drilling for gas from shale are being applied to oil drilling in shale.

It took two decades to perfect drilling and production techniques for shale gas, and it 

likely will not take nearly as long to maximize oil production from horizontal laterals. The 

technologies developed for shale gas are generally transferrable to pursuing oil from 

shale. That knowledge is starting to be applied on a wide basis to oil-bearing shales 

such as the Bakken, Granite Wash, Niobrara, and Eagle Ford. A renewed push for 

domestic oil based on the attractiveness of oil prices will be the catalyst driving 

continued improvements. An ample domestic resource base will encourage continued 

onshore drilling for both gas and oil from shales.