Fertile grounds

Horizontal drilling, oil-rich plays to fuel US onshore activity despite expected slide in oil prices

By Joanne Liou, Associate Editor

The onshore market has been a beacon for the global drilling industry, reflecting growth and improved efficiencies in the past year. This momentum is expected to guide the industry in the coming year. “The fact is that the strongest bit of the business has been US onshore activity,” John Spears, President of Spears & Associates, said. The 2014 US onshore count is expected to average 1,818, a 6% year-over-year increase, and to continue higher to 1,940 in 2015. “Activity has been strengthening for the past 12 months,” Mr Spears said. “It looks like it’s going to continue to trend a little bit higher into 2015.”

The US rig fleet can be divided into two categories: fit-for-purpose rigs drilling horizontal wells and older, conventional rigs drilling vertical wells. Utilization is nearly 100% for the horizontal-drilling rigs, “which is why we see this increase in rig construction,” Mr Spears explained. “Operators want to drill more horizontal wells but are having to sign long-term contracts so that rig contractors will build the rigs that they want to use.” On the other hand, older rigs that may not be able to efficiently drill horizontal wells are experiencing much lower utilization rates, approximately 30%, he noted. “Rig utilization across the whole US fleet is probably in the 65% to 70% range, but it’s really a tale of two markets.”

US oil production is projected to grow by about 13% in 2014 to 11.3 million bbl/day. “That has us worried about where oil prices are headed because we see a problem emerging,” Mr Spears explained. The majority

of that production increase is credited to land operations – the Lower 48 accounting for 90% of the growth, while offshore oil production accounts for only 10%. “Oil production is growing much faster than oil consumption and with very little growth in US oil demand,” leading to what Mr Spears believes will be a significant supply/demand imbalance.

WTI oil prices are expected to average $98.50/bbl in 2014, according to Spears & Associates. That is almost unchanged from 2013’s $98.10. Oil prices peaked mid-year to approximately $107 as the conflict between Russia and Ukraine unfolded, along with continuing unrest in the Middle East. Prices began to fall when it became apparent that the geopolitical tensions were containable, Mr Spears explained. “The oil traders of the world have gotten a little less nervous, and prices have come down accordingly. Oil prices have fallen further due to worries about the economic outlook for Europe and China.”

The outlook is dimmer for 2015, with oil prices sliding significantly in

October. Mr Spears said he expects oil prices to average $85/bbl next year, down by approximately 14%. “We’re looking at how fast US oil production is rising and believe that will keep domestic oil prices soft in the coming year,” Mr Spears said.

On the natural gas side, prices peaked above $5 per million BTU in Q1, leading to strong gas production. Prices have come down since then but are still expected to average $4.40 this year – a substantial increase from last year due to the cold winter of late 2013 to early 2014. “Gas prices this year will beup about 20% from where it averaged in 2013,” Mr Spears said. Unless the country experiences a colder-than-normal winter in the coming months, Mr Spears projects natural gas prices to drop to an average $4.10 per million BTU for 2015.

In terms of drilling, Spears and Associates estimates approximately 46,500 total onshore wells will be drilled by year-end 2014 and forecasts 50,000 wells in 2015. US onshore spending is expected to top out at $144 billion in 2014, and Mr Spears believes that will increase next year to $169 billion, a 17% increase. Average spending per well also will increase, he said, driven by the continued shift from vertical to horizontal drilling and by the increasing measured depths that are being drilled.

Dayrates, however, have remained steady. “We haven’t seen much change in dayrates, so I’m not expecting much of a change going forward,” Mr Spears said. “There will be about 150 new onshore rigs built this year and next, but the dayrates for those rigs are in line with the dayrates that exist for rigs that are out there.” Although dayrates vary region to region, on the whole they are averaging $25,000 to $26,000, he said.

A defining trait of the latest wave of newbuild orders is that they are not being built on speculation. Contracts for two to three years of firm work are helping drilling contractors secure financing for the rigs’ construction, Mr Spears said.

Trinidad Drilling, which has 54 land rigs operating in the US and 60 in Canada, currently enjoys 100% utilization. The company is building five rigs against multi-year, take-or-pay contracts for US shale operations in Texas, Louisiana and Mississippi. “Our opportunities are always market-driven,” Carlton Campbell, Senior VP of US Operations, said. The 1,500-hp AC rigs will be equipped with walking systems and 7,500-psi circulating systems. The rigs, which are being constructed by Trinidad’s manufacturing division in Houston, are expected to be delivered in the first three quarters of 2015.

Analyst: LNG exports could boost US gas drilling activity 40-50% by 2020

By Joanne Liou, Associate Editor

The US continues to position itself to take part in the growing global LNG market. In 2009, the US surpassed Russia in natural gas production. US production is expected to grow by 5.4% in 2014 and by an additional 2% in 2015, according to the US Energy Information Administration (EIA). In terms of volume, the US is expected to produce nearly 70 billion cu ft/day (Bcfd) this year and approximately 85 Bcfd by 2020.

“Most of that increase will go to the export market,” John Spears, President of Spears & Associates, said. “Relative to 2014, we expect to see a 40-50% increase in gas well drilling activity by 2020 as these export projects really get up and running. Most of the increase in gas well drilling is expected to take place in the Marcellus/Utica Shale and in Texas and Louisiana.”

The worldwide LNG market is currently about 30 Bcfd. “Given all the new supplies and some of the projected demands, we could easily see the LNG market by 2030 to double in size,” Dr Kenneth Medlock III, a James A. and Susan G. Baker Fellow in Energy and Resource Economics, said.

“It’s a market in transition,” he continued. “The investments and the planning that go into developing LNG supply – export capability, liquefaction – it’s a long process. When you have an unexpected surge in demand, as was the case following the disaster at Fukushima, existing supply capability is stressed, and prices rise dramatically as a result of the constraint.” Dr Medlock is also Senior Director at the Center for Energy Studies of the James A. Baker III Institute for Public Policy and an Adjunct Professor of economics and civil and environmental engineering at Rice University.

For the US, higher prices in other markets around the world continue to stimulate interest to export. “European prices are roughly double what they are (in the US), and Asian prices are close to triple. That’s going to create a lot of opportunities for arbitrage,” which refers to companies taking advantage of the price difference between US and other markets. “As you have more players in the marketplace, it actually creates additional opportunities for trading. You’re going to see a lot of that start to happen as these new supplies come into the market over the next 10 years,” Dr Medlock said.

The US has only one LNG export facility in operation – ConocoPhillips’ Kenai LNG Plant in Alaska. It ships mainly to Japan. As of mid-October, the US Federal Energy Regulatory Commission (FERC) had approved four new LNG export facilities in the Lower 48 – two in Louisiana, one in Texas and one in Maryland. FERC most recently approved Dominion Energy’s Cove Point LNG liquefaction and export project in Maryland on 30 September. Cheniere Energy’s Sabine Pass project in Louisiana was the first to receive approval in April 2012. That facility is projected to come online in late 2015.

Dr Medlock sees a “very rosy picture” for drilling activity in North America and a positive impact as a result of LNG exports. “You’ll see more interest in long-term sustainable field development,” he said, with “interest going back into places people kind of walked away from, like the Haynesville in northern Louisiana because it’s a relatively expensive gas play. But if you have strong demand just south of there coming out of Sabine Pass and maybe even out of the Cameron facility (in Louisiana) in the next five years, it’ll give enough price support and enough demand pull to encourage capital back there.”

Leading plays

Operators continue to focus on high-return oil-rich plays, driven by high oil prices and horizontal drilling “The oil price is supporting a lot of the activity. Plus, there’s a lot of activity transitioning to development drilling, where our walking rigs are needed,” Tom Horton, VP of Business Development and Contracts for Trinidad Drilling, said. “The price of oil and technology have made drilling more commercial.”

In the US, the busiest tight oil plays are the Eagle Ford, the Permian and the Bakken, said Ben Shattuck, Research Analyst at Wood Mackenzie. They are expected to remain the top three plays in 2015, as well. “Then you have the shale gas plays, and the headliner, far and away, is Marcellus in terms of current activity.”

Ramp-up in the Permian

The Permian Basin has been the poster child for increasing activity. In the ramp-up phase, an increase in capital expenditure is expected as operators add rigs to their activity, driven primarily by strong results out of the play. In the Permian, this phase is expected to last until mid-2015. Key players here include Pioneer Natural Resources, Devon Energy and Apache Corp. Annual capital spending in the Permian’s Wolfcamp Shale is forecasted to reach $17 billion by 2017, overtaking the Bakken, according to Wood Mackenzie. More than 1,500 wells are expected to be drilled in the Wolfcamp in 2014. Other oil-prone plays, such as the Bakken, are also experiencing upticks, as are smaller areas like the Denver-Julesburg Basin.

Characteristic to the ramp-up is the adoption of horizontal drilling. In the Permian, the horizontal rig count has exceeded the vertical rig count for the first time in history, according to Wood Mackenzie. “We’ve seen horizontal rig count (in the Permian) grow from almost nothing three years ago to the point where it’s accounting for a very high percentage – more than 50% – of  the rigs working there today,” Mr Shattuck said.

The horizontal rig count is now hovering around 240 in the Permian, up from 140-180 last year. Although a certain amount of vertical drilling will remain, “we expect the horizontals to dominate for the foreseeable future,” Mr Shattuck said. Rig count, including both vertical and horizontal rigs, was approximately 560 in October.

By the end of the decade, analysts project total crude plus condensate production to reach approximately 2.1 million bbl/day in the Permian, while natural gas and NGL production is expected to reach 3.5 million bbl/day in the basin.

Marcellus in transition

Rig activity continues to migrate to two key areas within the Marcellus: Northeast Pennsylvania and Southwest Pennsylvania. Although the northeastern part of the play is strictly dry gas, the amount of production from the wells is driving the economics, with as much as a 14 bcf average per well for an expected ultimate recovery, Mr Shattuck said. Wells in the southwestern part of the state are not quite as big, but they have an NGL component. “That NGL uplift supports the economics of the southwest part of the play, and that’s why activity has remained in that area.”

“You saw a refocus on the core areas of the Marcellus that were economic, and despite the fact that rig counts fell, we’ve seen production growth,” Mr Shattuck continued. In 2011, the rig count was more than 120, and Wood Mackenzie expects rig count to average in the 80s for 2015. Production has more than doubled from approximately 6 billion cu ft/day (Bcfd) in 2012 to 13 Bcfd in 2014. “We expect to see a continued increase to about 14 Bcfd of gas in 2015.” The Marcellus accounts for almost 40% of US shale gas production, according to the US Energy Information Administration. In comparison, the region was producing only 2 Bcfd in 2010.

Increased production from the Marcellus could lead to record natural gas storage injections, the EIA reported on 5 August. “Rising production in the Marcellus has outpaced growth in the region’s pipeline capacity, which has resulted in multiple pipeline expansion projects focused on removing bottlenecks in the Marcellus. As pipeline capacity is increased, markets in the Northeast gain greater access to Marcellus region gas, which can result in stabilized or decreased prices.”

Eagle Ford development

The Eagle Ford is in full-scale development mode, with more than 200 rigs at work, Mr Shattuck said. “It has some of the most attractive returns – a function of being in full-scale development – and it attracts a lot of capital.” Approximately 3,300 wells are

expected to be drilled by year-end 2014, according to a Wood Mackenzie press briefing. Mr Shattuck believes that number will remain relatively flat for 2015. “Operators are becoming more efficient with drilling and completing the wells. They’re able to do more in a shorter period of time,” he noted. “The number of wells drilled tends to be flatter in the development phase than in the ramp-up phase. It’s more of an efficiency game at this point.”

The production mix in the Eagle Ford is divided among three types: oil, condensate and gas. “The best returns are in the condensate window of the play,” Mr Shattuck said. Production in the Eagle Ford is expected to increase through this decade to 3.5 million bbl of oil equivalent, of which crude and condensate will account for nearly 2 million bbl/day.

Since 2009, production rates have steadily increased. However, first-year decline rates remain high and fluctuate between 60-70%, according to the EIA. “Decline rates over the second year of production have steadily increased from 30% for wells drilled in 2009 to nearly 50% for wells drilled in 2011 and 2012,” the EIA stated. “Since 2013, many producers have been using significantly more proppant when hydraulically fracturing new wells, which appears to have increased initial production rates but lead to a steeper drop in production.”

Spending in the Eagle Ford is expected to remain flat or see a slight decline as a result of more efficient operations. Analysts at Wood Mackenzie expect $27 billion in capital expenditure in the Eagle Ford for 2014. “In development mode, you tend to get more efficient in both the time and money, so we’ll see a relatively similar number of wells drilled (in 2015), and operators will more than likely be able to do that for less money,” Mr Shattuck stated.

For horizontal drilling projects, the rig accounts for about 20% of the budget, but the completion – including hydraulic fracturing – is 40-50% of the cost of the well. “In terms of where the dollars are going, most of it, at least for horizontal wells, is on that completion side,” Mr Spears said, referring to fracturing services, such as pumping equipment and materials.