Eagle Ford oil production tops 535,000 b/d in five years

In 2008 production from the Texas Eagle Ford shale was 352 b/d of oil and 57 Mcm/d (2 MMcf/d) of natural gas, which doesn’t even register on the scale of world-class. At the end of April 2013, production had skyrocketed to 536,117 b/d and 60.6 MMcm/d (2.14 Bcf/d), according to the Texas Railroad Commission (TRRC), making the play definitely world-class. Five years ago no one would have imagined a whopping increase of 152,206% in daily oil production from the Eagle Ford.

In the “Eagle Ford Shale Task Force Report,” March 2013, TRRC Commissioner David Porter said, “The Eagle Ford shale has the potential to be the single most significant economic development in our state’s history.” Experts’ projections confirm Porter’s prediction, with capex in the Eagle Ford shale expected to reach nearly US $30 billion in 2013, according to the report.

The Eagle Ford shale also has the potential to become the most active oil and gas play in North America, with approximately 235 drilling rigs working, according to the 2012 Baker Hughes rotary rig count. Operators forecast that the play will continue to develop for decades to come, stated the report. Table 1 lists the top oil and gas producers in the play.

Eagle Ford formations spur interest

The Eagle Ford shale is a Cretaceous formation that lies between the Austin Chalk and the Buda Lime at a depth of approximately 1,220 m to 4,268 m (4,000 ft to 14,000 ft). It is the source rock for the Austin Chalk formation, the report added.

The Eagle Ford is the reason for all the interest, but the Austin Chalk, Buda, and Pearsall formations are all attracting attention as well. Exco Resources recently spent $680 million to acquire proved and producing reserves from Chesapeake Energy in the Eagle Ford. But, as Doug Miller, Exco chairman and CEO, said on a conference call on July 8, “There is potential in different zones, including the Buda and Austin Chalk. We will start reviewing and evaluating that area right after closing. Hopefully we will find something."

TABLE 1. Top 20 producers in the Eagle Ford shale as of Feb. 25, 2013 (largest to smallest).

Sanchez Energy is a mid-cap operator that “built a solid base under this company as a pure play Eagle Ford oil company so far,” Tony Sanchez III, president and CEO, told E&P. However, “we are drilling an Austin Chalk well right now. Both the Buda and Austin Chalk are statistical type plays and are not as commercially productive over as wide an area as the Eagle Ford.”

The company has people assigned to map out the fracturing systems in the Buda and Austin Chalk “since you need to rely on natural fracturing more in those formations than in the Eagle Ford,” Sanchez continued. “The other potentially big formation is the Pearsall. We’ve drilled and cored one well, and we have plans to drill and core other wells that we will complete as Eagle Ford producers. But we’re gathering data.”

Sanchez Energy is seeking opportunities to swap data on the Pearsall. “I think the indications so far are that there is a lot of potential, but it is still early. The risk is that there is a lot more gas in the Pearsall. However, it is very thick – 152 m [500 ft] – which means you need to figure out where you want to put your laterals within that formation. On all three of those formations we are investing a little capital, but we are not risking any material capital until we have a better sense of where and how to drill,” he said.

Overall in the Eagle Ford, though, operators have identified the three fairways – oil, wet gas, and dry gas – and are targeting primarily the oil sweet spots. Given the size of the Eagle Ford, which is roughly 80 km (50 miles) wide and 644 km (400 miles) long, there is still a lot of exploration under way.

Building on success

The exploration, though, takes a back seat to oil production. Companies are now focusing on “harvesting” the Eagle Ford. And recent quarterly reports support that emphasis with targets for production continuing to rise.

Sanchez Energy is currently producing about 12,000 boe/d, with 85% of that volume crude oil. The company expects to be between 16,000 boe/d and 17,000 boe/d by year-end 2013 and at 22,000 boe/d by year-end 2014. The company’s capital budget for 2013 is about $500 million. About 90% of that budget is for drilling and completion.

“We’re high-grading our acreage,” explained Sanchez. “So 140,000 net acres may turn out to be 130,000 or 120,000 net acres depending on how we choose to focus. Like the rest of the industry, we have moved into the harvest mode. We see the clear benefit of efficient capital deployment by focusing on large, contiguous blocks of acreage as opposed to holding acreage. Our mindset has turned entirely to harvesting our acreage and getting the proved reserve component of our asset base built up and production volumes ramped up.

“That drives things like pad drilling. The vast majority of our drilling is multiwell pad drilling so that we can amortize costs over several wells and make more efficient use of surface facilities,” he continued. “We save on road costs. We’re using walking rigs that can move in any direction on the pad. We’re saving $300,000 to $500,000 per well just on rig mobilization costs by using pad drilling.”

Reducing well costs and drilling time is the name of the game in the Eagle Ford. Chesapeake was operating 15 rigs in the play at the end of June. Because of reduced cycle times and the sale to Exco, the company planned to reduce its operated rig count to 10 by year-end 2013, according to its second quarter report. Average spud-to-spud cycle time during the quarter was 16 days, down from 21 days the year before.

During 2Q 2013, Chesapeake connected 140 wells to sales, an increase from the 111 wells connected during the first quarter. Net production averaged about 85,000 boe/d, which is an increase of 135% year over year. About 66% of the company’s second quarter production was oil, 14% was NGL, and 20% was natural gas. As of June 30, 2013, Chesapeake had 795 producing wells, 24 wells waiting on pipeline connection, and 144 wells in various stages of completion.

In 2010, Statoil entered into a joint venture with Talisman Energy USA Inc. and now holds 73,000 net acres in the Eagle Ford with net production of 20,200 boe/d. The companies had agreed to phase in operatorship of half the assets at a later stage. And, as of July 1, 2013, the Norwegian company became the operator for the eastern half of the asset in Live Oak, Karnes, DeWitt, and Bee counties. Talisman will remain as the operator for the western half in McMullen, La Salle, and Dimmit counties. Statoil had previously begun operating three drilling rigs in the area.

In its second quarter report Talisman reported that its drilling and completion costs in the first half of 2013 were about $8 million per well, down from $11.1 million per well in 2011. Drilling cycle times were reduced to 21 days. As a result of the lower costs, the two companies were able to further reduce their rig count by one to five rigs while remaining on track to deliver the same number of drilled wells. In its March 2013 investor presentation, Talisman said it expects its net production to rise from 15,000 boe/d in 2012 to 58,000 boe/d in 2015.

Pioneer Natural Resources plans to drill 130 Eagle Ford wells in 2013. With lateral lengths averaging 1,676 m (5,500 ft), the wells cost $7 million to $8 million each. In its second quarter report the company touted its efficiency improvements. The number of wells drilled from pads is expected to increase from 45% of total wells in 2012 to 80% of total wells in 2013.

On each pad Pioneer drills all the wells before stimulating any of them. Pad drilling saves the company $600,000 to $700,000 per well, allowing the company to drill 130 wells with 10 rigs in 2013, compared to a similar number of wells drilled in 2012 with 12 rigs.

The company also is saving money by using white sand proppant in deeper wells instead of ceramic proppants. The company fracture-stimulated 39 wells with the white sand proppant this year, saving $1.1 million per well. Pioneer is monitoring performance of direct offset wells using the different proppants. Early performance over the last two years from wells fractured with white sand has been similar to results from wells using ceramic proppants, according to the quarterly report.

Growing acreage, reserves, production

The opportunities for companies to tap into the Eagle Ford are abundantly available. Operators continue to farm out acreage and create joint ventures to drill and develop acreage. Sanchez Energy is an example of growth in the play. From 2008 to 2009 the company started looking for opportunities to get some oil exposure. Until that point, the company’s predecessor had been a Gulf Coast gas prospector.

“We took a couple of our geologists and mapped out the trend. We said we wanted to get into areas where, if the oil window of the Eagle Ford works, we’ll be in a good spot. And if it doesn’t, we will have the Chalk as a bailout above it. That is when we took our Maverick [Zavala and Frio counties] and Palmetto [Gonzales County] positions. It turns out that Palmetto is right in the middle of the best part of the trend,” Sanchez said.

When gas prices crashed in 2009, the company took its capital and refocused on oil. Sanchez did a joint venture with Hilcorp that funded the drilling on the Palmetto area. Hilcorp ultimately sold its 50% interest to Marathon. Sanchez owns 50% of Palmetto and 100% of Maverick. In mid-2011 the company had about 38,000 net acres. The company was evaluating its 2012 budget and decided to go public.

“At that time we had 10 producing wells and 600 boe/d of production. Subsequent to the initial public offering, we acquired our Marquis acreage, which was 55,000 net acres, all undeveloped. We went from 38,000 to 93,000 acres, but we still had only 10 producing wells. We then acquired from Hess what we call our Cotulla area [Frio, La Salle, Dimmit, and Zavala counties], which is about 44,500 net acres, earlier in 2013,” he continued.

“Today we have about 115 producing wells, and by the end of the year we’ll be at about 150 producing wells and 15,000 to 17,000 boe/d. Our proved reserves went from 3 MMbbl to 36 MMbbl,” he added. “We think we have in excess of 1,000 drilling locations, which could be upwards of 1,500 locations depending on how we space the wells. Right now we are estimating between 1,200 and 1,500 locations.”

Sanchez Energy is testing 40-acre spacing in its Palmetto area and is drilling on 60-acre spacing in the Marquis and Cotulla areas and 80-acre spacing in the Maverick area. The Palmetto area is the most productive, followed by Marquis, Cotulla, and Maverick.

“Why did we buy Cotulla if it is not at least equal to Palmetto?” Sanchez asked. “There is a risk-return reason. Those are very low-risk reserves we added in Cotulla. We could be done drilling that area inside two years, and then we could use that free cash flow to fund other opportunities. Alexander Ranch in the Cotulla area is our main focus right now.”

There are still deals to be made in the Eagle Ford, and finding the right acquisition can make or break a company. Exco looks at its acquisition from Chesapeake as a win-win for both companies. The package included 55,000 net acres, 120 total producing wells (94 in the Eagle Ford), about 6,100 boe/d of production, and a farm-out option on about 147,000 net acres.

The acquisition closed July 31 for total consideration of about $685 million in cash, subject to post-closing price adjustments. At the same time, Exco signed a participation agreement with affiliates of Kohlberg Kravis Roberts & Co. (KKR) to sell an undivided 50% interest in the undeveloped acreage for $131 million. Exco and KKR will jointly fund future development costs. For each well drilled, KKR will fund and own 75% of the well, and Exco will fund and own 25%. After one year of production from the wells drilled in each quarter, Exco has the right to purchase KKR’s 75% working interest at fair market value. Exco would be able to make its first offer in 4Q 2014.

The farm-out acreage equates to about 225,000 acres gross. The partner in that acreage with Chesapeake was CNOOC. Exco will continue to partner with CNOOC in that acreage. “Chesapeake has a 2% override in the farm-out agreement and the right to convert that to a 25% working interest as we drill the wells. So there is an upside for both of us in the farm-out,” Miller said.

Exco has been very successful in reducing drilling and completion costs in the Haynesville, he said. “Chesapeake has done a great job on drilling and reducing costs. We have some new techniques that we recently completed in the Haynesville. If these can be converted to work in the Eagle Ford, we’re hoping to get those costs down even further.”

Right now, Exco can get good returns down to $75/bbl on oil. The company is spending $7.2 million per well currently. If the company can get costs down to $6.5 million per well, “we can reduce the oil price we need down to $70/bbl or even $65/bbl. That’s what we’re planning on doing,” Miller said.

“I think there is such a thing as a good deal on both sides. There is plenty of upside potential in the farm-out acreage for Chesapeake. The one thing that took us a long time to do is creating the farm-out and making sure everyone agreed to it,” he continued.

In the KKR joint venture, “we have 300 identified locations from a drilling standpoint. We are planning on five rigs initially. We are planning on starting the rigs Sept. 1,” he added.

Companies boost efforts in oil window

The most productive well in the Eagle Ford was completed in the eastern acreage of EOG Resources. “We set a record with the completion of the Burrow Unit #5H [in Gonzales County], which had an initial production rate of 7,515 b/d and 6.88 MMcf/d [194.8 Mcm/d] of liquids-rich gas,” said Bill Thomas, EOG president and CEO, on the company’s 2Q 2013 results call on July 7. “Consistently, the No. 1 driver for better wells in all areas is improved frac techniques, and that is the case for the Burrow 5H.”

The company also had three other big producers in the quarter in the Wilde Trust Unit, also in Gonzales County. The wells and initial oil and liquids-rich gas production rates include Wilde Trust Unit #1H, 5,475 b/d and 198 Mcm/d (7 MMcf/d); Wilde Trust Unit #2H, 6,520 b/d and 161.4 Mcm/d (5.7 MMcf/d); and Wilde Trust Unit #3H, 5,525 b/d and 175.6 Mcm/d (6.2 MMcf/d).

EOG is the largest oil producer in the Eagle Ford with about 173,000 boe/d net as of June 30 and 639,000 net acres. The company is currently operating 25 drilling rigs.

“Drilling and completion improvements continued to drive down well costs,” Thomas said. “As a result, we have lowered the average completed well cost in the Eagle Ford from $6 million to $5.5 million, and we have increased the number of wells we plan to drill this year from 425 net wells to 440 net wells.”

As an example of how frac techniques and longer laterals have improved wells, he noted that wells drilled in the Keller and Smart units in 2013 showed a 30% improvement in average cumulative oil production for 120 days compared to offset wells drilled in 2012.

EOG also has reduced the time from spud to total depth to less than 10 days from about 17 days in 2009. There are about 4,900 drilling locations yet to complete on 40-acre spacing in the eastern area of its holdings and 65-acre spacing in the western area. The company booked 552 MMboe proved reserves as of Dec. 31, 2012. As of February 2013, its estimated potential reserves were from 1.6 Bboe to 2.2 Bboe net to EOG, the company reported.

Smaller companies also are taking advantage of the business climate. Bob Watson, president and CEO of Abraxas, said about the company’s McMullen County operations in a 2013 production update on Aug. 1, “3Q 2013 promises to be exceptional for Abraxas as we benefit from the two high-rate Eagle Ford wells added late in 2Q 2013 and three other recent Eagle Ford completions. We look forward to providing the market with the early results from our 40-acre pilot in the Camaro B-3H and Camaro B-4H.”

The company’s Sting Ray A-1H averaged 1,033 boe/d on a restricted choke over its first 30 days of production, while the Corvette A-1H averaged 589 boe/d over its first 25 days.

In a July 25 operations update, Cabot Oil & Gas Corp. noted it was continuing to drive down well costs, leading to further increased returns. The company operated one rig during 2Q 2013. “Based on these results, we are bringing in a second rig at the end of July that will focus solely on pad drilling, which we anticipate will result in cost savings of more than $500,000 for a typical well,” said Dan Dinges, Cabot chairman, president, and CEO.

Cabot’s first extended lateral was drilled to a length of more than 2,439 m (8,000 ft). The well had a 24-hour peak flow rate of 1,130 boe/d. After 120 days of production, the well was still flowing about 1,100 boe/d, the company stated.

Austin Exploration Ltd. closed a farm-out on July 30 with Halcon Resources Corp. for further drilling in the former’s Birch project in Burleson County. Under the agreement, Halcon will earn a 70% interest in the Birch project by funding 100% of the next three wells with an estimated cost of $24 million to $27 million. The farm-out covers about 4,221 acres.

Halcon will make a $1.9 million upfront payment for an 18-month exclusive drilling option, during which the three wells must be drilled. Also included in the farm-out is a 70% interest in the B1 Krueger and B3 Schwartz Galbreath wells and associated acreage.

Richard Cottee, chairman of Austin Exploration, said in a July 30 press release that the farm-out will allow the company to develop its Eagle Ford asset while concentrating its efforts on a larger prospect in the Niobrara that has proven commercial hydrocarbons.

UNCONVENTIONAL APPROACH POWERS NATURAL GAS PRODUCTION

Temporary power solutions help unconventional gas drilling operators in plays like the Eagle Ford minimize capital spending and boost productivity.

By Brian R. Fahnestock, Aggreko LLC

When expanding unconventional gas drilling operations that are off the power grid, where you are today isn’t likely where you will be tomorrow. Producers of all sizes often face a common dilemma: when and how to scale up operations where there are no power sources. For them, time is money when the discovery of a lucrative oil or gas resource occurs. Unfortunately, sometimes they wish they could scale down with no penalty and move to the next location.

The vast natural gas production operations in US locations such as the Eagle Ford shale are distributed far and wide and require different power solutions. Some are powered through direct connection to the existing utility grid, while remote operations require their own power generation solutions to quickly ramp up into a production state.

Many operators in unconventional gas production are leveraging customized temporary power generation solutions designed to match their particular onsite requirements to:

• Power wells ready to come online where grid power is unattainable;
• Supplement new overhead power lines running above or below ground;
• Run several well sites at once via a mobile power plant or microgrid power approach; and
• Demobilize and move to the next well site rapidly and at minimal cost.

Using site gas as fuel

Temporary rental power provides several tangible benefits, such as allowing operators to avoid delays, increase productivity, and capture short-term market opportunities in their overall production plans. Furthermore, many temporary power solutions are designed using site gas as fuel, ensuring that state and federal environmental regulations are met. In addition to savings in fuel, rental solutions also help an operator improve the balance sheet by avoiding high-cost capex commitments on short- to mid-term duration needs.

For example, one North American operator was developing in remote areas without grid power and wanted to be prepared to scale up when the wells began producing. Therefore, an alternative power source was needed to advance its expansion strategy.

A customizable and scalable solution providing reliable, consistent electricity to the developing area was provided by temporary power provider Aggreko to address the operator’s different growth phases and shifting drilling locations.

Microgrid power

As wells were first coming online, 40 mobile natural gas generators were installed using well gas. This enabled production to occur while overhead power lines were constructed. When the overhead transmission was in place but not yet ready for utility integration, the initial generators were replaced by a single natural gas microgrid using four 1.3-MW units, akin to that of a central power plant. The microgrid was then connected to overhead lines, positioning the operator for maximum efficiency until a local utility was ready to carry the load.

This application is just one example of how to leverage a customized and scalable solution for short- and long-term needs.