The largest coalbed methane (CBM) development in the world is under way in Australia. The CBM, which in Australia is referred to as coalseam gas (CSG), will supply export markets. The Queensland Curtis LNG plant will be the first facility to begin liquefaction in 2014, followed by Australia Pacific LNG (APLNG) and Gladstone LNG (GLNG) in 2015. Total output from the three plants will be more than 24 million metric tons per year (1.17 Tcf/y), which equates to about 99 MMcm/d (3.5 Bcf/d).

With economic demonstrated reserves of CSG estimated at 924 Bcm (33 Tcf), there should be enough gas to supply the projects easily for more than 20 years. But getting that gas out of the ground and delivering it to the LNG plants in a timely manner can be daunting.

“The numbers are pretty staggering. We’re talking about fully developing two basins. And this gas already is committed,” Michael Zuber, adviser at Schlumberger for unconventional gas in the Asia area, said during Hart Energy’s DUG Australia conference in Brisbane on Aug. 29. “They are talking about drilling between 1,000 and 2,000 wells per year for the foreseeable future. The level of activity is going to be daunting. By 2020, about 19,000 wells will be drilled.”

Innovation is needed in terms of optimizing solutions and minimizing costs. “You can see today we have drilled a small percentage of all the wells that will be drilled,” he continued. “We know the performance of a very small number of all these wells. The challenge on the upstream side is to really deliver these volumes. A big part of what has been happening in the last few years is exploration within these coal fields to try to find out the places to avoid and the places where we really want to go.”

Drivers, challenges for Australian CSG

Schlumberger Business Consulting looked at initial production rates and also initial reserves in CSG wells for some of the projects in eastern Australia. For the most part, initial rates were less than 28 Mcm/d (1 MMcf/d) with reserves less than 142 MMcm (5 Bcf). “The scale is based on finding and development [F&D] costs. Obviously, F&D costs go up as the performance goes down. As the reserves per well go down, you have to drill more wells,” he explained.

The idea that producers will easily find some great sweet spots to fill the LNG trains is misleading. There will be huge variability and distribution in those 19,000 wells that the industry will experience, he added.

“Because we are basically committed to drilling a lot of wells and delivering oil and gas, we clearly want to optimize where we put that money. We want to drill in the good places first because it requires less investment,” he said.

As Zuber said, permeability is a big driver in CSG development based on how these coals are cleated, depth of burial, where they are found in structural terms in the basin, and stress fields. Based on those factors, there is a wide range of permeability.

Low-permeability coals are an issue. Operators have found that these coals become problematic since it takes more technology and more investment to produce the wells. “That’s a challenge,” he noted. “To deliver a certain amount of gas, you need to drill more of these wells, and perhaps they are more costly. The whole process basically spins out of control. This is one of the reasons we are looking for shale and tight gas right now.”

Geologic complexity and the ability to predict performance also are challenges. Operators need to look at the design of every well in terms of geology to get the most out of the coals. The ability to predict performance in CSG is not that easy to do. Prediction requires lots of data, Zuber said.

One other big issue Zuber pointed to is the ramping up of gas production. Lots of wells are being drilled and shut in, “waiting on the day when the LNG plants are turned on and we can bring these wells online. This is very unique in terms of CSG. Typically for CSG, you drill the wells, complete them, put them online, and get them producing and dewatering. Ideally you never shut them in. This startup is going to be a unique experience in the world of CSG. There is going to be a learning curve and lots of fits and starts.”

In Queensland, operators really need to shorten the learning curves. They need to better understand the reservoir and get more rapidly to optimized solutions. Integration and innovation are needed, bringing together a lot of stakeholders, he added.

Projects working together

Origin has the longest track record in CSG, drilling its first exploration well in Queensland in 1993. Today it is the leading producer in Australia. With partners ConocoPhillips (37.5%) and Sinopec (25%), Origin (37.5%) owns APLNG. As of June 30, 2013, 45% of its upstream and downstream projects were complete. The first train is scheduled to begin production by mid-2015 and the second train by late 2015.

The company has drilled 343 wells and laid 73% of its pipeline from Condabri to Gladstone. Even with this progress, Origin is shoring up both its CSG supply and sales. In April 2013, the company signed an agreement to buy 4.6 Bcm (163 Bcf) for 10 years from Beach Energy starting in 2015. It signed another agreement in September with Esso/BHPB for 11.5 Bcm (407 Bcf) for nine years beginning in 2014. A sales agreement was signed with its rival GLNG for 9.7 Bcm (344 Bcf) for 10 years starting in 2015.

On Oct. 25, 2013, the company also signed agreements with GLNG for gas swapping and infrastructure connection, the companies said in a press release. The new agreements are expected to make gas transportation more efficient between the two projects’ gas fields in the Surat basin and the corresponding LNG plants in Gladstone. Under the terms of the agreements, two pipeline connection points will be built between the GLNG and APLNG infrastructure, and a number of gas swap agreements will be undertaken to minimize gas movements and operational costs.

This type of integration will be beneficial in assuring the CSG projects will be able to meet the demand of the LNG plants.

India prepares CBM bidding policy

According to the Directorate General of Hydrocarbons (DGH) database, India has an estimated 2.6 Tcm (92 Tcf) of CBM gas reserves. As the world’s third largest producer of coal, however, commercial production of CBM is still at a very nascent stage in the country. The Indian government is now coming to grips with its policy for CBM exploration.

On July 12 a CBM policy was proposed to provide incentives to Coal India Ltd. (CIL) to exploit gas in its coal blocks. Under the policy, the state-owned firm would not have to bid for the blocks since it already owns them. The government already has bid out 33 CBM blocks to noncoal companies, including Oil and Natural Gas Corp. (ONGC) and Great Eastern Energy Corp. Ltd. (GEECL).

That created a furor with the oil minister, Veerappa Moily, who rejected the draft note for the Union Cabinet, directing officials to redraft it, according to the Economic Times. Under India’s mining laws, coal mining is the mandate of the coal ministry while the oil ministry regulates CBM exploration.

Moily criticized the draft note, saying that CIL was not an expert in CBM exploration any more than ONGC was an expert in coal mining. He put a new team of officials in charge of redrafting the note, which was expected to be ready by November.

The Economic Times stated that some bureaucrats in the oil ministry wanted to avoid any controversy by not allowing private investment in those coal blocks. By favoring only public-sector companies, the bureaucrats would be immune from investigative agencies. However, such a move would put a damper on CBM exploration.

Although the government is still wrestling with CBM policy, the industry continues to move ahead. On June 5, ONGC announced in a press release it will give 10% to 25% stakes in its four CBM blocks to Dart Energy Ltd. in an effort to expedite production. ONGC finalized its partners for producing CBM in its Jharia, Bokaro, North Karanpur, and Raniganj blocks.

A company official said Dart will get 25% each in the Jharia, North Karanpur, and Bokaro blocks, where Dart would be the lead partner, and 10% in the Raniganj block.

On May 20, GEECL said it won a 25% stake in ONGC’s Raniganj CBM block in West Bengal.

The Raniganj (North) block is next to GEECL’s Raniganj (South) block. The DGH estimated that Raniganj (North) holds in-place gas reserves of 42.5 Bcm (1.5 Tcf). GEECL owns 100% of Raniganj (South), which began CBM production in 2007. The company received approval to drill an additional 200 wells in the Raniganj (South) block with production beginning in 2018.

Indonesia pushes CBM

Although Australia’s three LNG plants under construction in Queensland are relying on CBM for feedstock, these are not the first LNG plants to liquefy CBM. BP began selling CBM to the Bontang LNG plant in East Kalimantan several years ago when conventional resources were not able to provide enough feedstock.

In Indonesia the coal seams are up to 50% thicker than similar deposits in the Powder River basin in Wyoming, the coals are shallower, and the gas content is very high. Netherland Sewell & Associates Inc. has estimated gas content in East Kalimantan at 8.5 cm/ton (300 cf/ton), about six times that of the Powder River basin.

In the Barito basin in South Kalimantan the geology is really spectacular, Scott Stevens, chairman of CBM Asia, said. “It is super thick, more than 100 m [330 ft], and there are gas kicks in all of the well logs so there clearly is gas in the coals. And there’s almost no faulting. It’s geologically very simple, and it has huge potential.”

Recently, the company entered a joint venture agreement with ExxonMobil. Stevens said that Exxon entered Indonesia a few years ago and acquired majority stakes in four production-sharing contracts. Exxon drilled six wells, confirmed the good geologic conditions, and then sought a low-cost partner. “We were in the right place at the right time,” Stevens said. The companies are planning a five-well pilot project this year.

In an Aug. 22 press release, CBM Asia said that Exxon-Mobil agreed to extend the umbrella agreement signed Dec. 19, 2012. “Our confidence in the commercial viability for CBM in Kalimantan is high, and we look forward to success in the coming drilling season,” Alan Charuk, president and CEO of CBM Asia, said.

On the Sekayu production sharing contract (PSC), Medco Energi, operator, resumed production testing of the CBM-02 well May 23, 2013. A new high-capacity submersible pump was installed, dewatering the well at the rate of 3,000 b/d of water from the Palembang coal seams. Gas production initiated almost immediately, increasing as the well dewatered.

At the Kutai West PSC, Newton Energy, operator, began completion and stimulation operations in four coal seams in the KW-CBM-01 well in September.

Small-scale CBM-to-LNG plant

CBM Asia Development Corp. signed a non-binding memorandum of understanding (MoU) with a multinational gas company to conduct a technical and market study of a CBM-to-LNG facility with a potential capacity of up to 1.4 MMcm/d (50 MMcf/d) in South Kalimantan, Indonesia, the company said in a press release Sept. 26.

As specified under the MoU, CBM Asia’s responsibilities are to conduct a commercial analysis on the CBM development strategy required to meet the proposed LNG facility capacity and to produce a technical study to determine gas production schedule, reserve certification, and natural gas delivery points.

The gas company will conduct market analysis on the demand for LNG and undertake an infrastructure study on construction of the LNG facility and related logistical groundwork. Each party is responsible for its own costs in relation to the study.

On completion of the study, the two companies will jointly decide on the feasibility of the project with a view to entering into a definitive agreement on the establishment of a business relationship. The proposed business structure would require CBM Asia to supply natural gas whereas MGC would offtake gas; build, own, and operate the LNG facility; and market/ deliver the LNG to the end consumer. The potential CBM field development, gas sales contract, LNG facility construction, and other related works would remain subject to local, regional, and central government approvals.

“From a development perspective the potential establishment of a medium-scale LNG facility with a capacity of up to 1.4 MMcm/d provides the crucial mid-development step beyond early-stage power generation toward development of new pipelines and/or large-scale LNG facilities required for full-scale development of the Barito basin’s vast CBM potential,” Charuk explained.

Chaotic CBM development in China

If the experience of Green Dragon Gas is any indication, the CBM industry in China is somewhat chaotic. In an Oct. 9 press release, the company said it was surprised to find out that its Chinese partners had drilled 1,500 wells on five of its six CBM licenses – without the knowledge of Green Dragon Gas.

The company didn’t find out about the wells until five of the licenses were reissued by the government in July. The company estimated that about US $500 million was spent in total on all 1,500 wells. The wells could boost the company’s reserves at the next independent evaluation as well as add to its gas production without it having spent any money on exploration. With the newly discovered wells, the company could meet its production target of 510 MMcm (18 Bcf) of gas by 2014. Green Dragon Gas also has reengaged Greka Drilling to drill wells over the next six months.

Green Dragon was confirmed as the official license holder by the government despite claims from China United Coalbed Methane Corp. The company was waiting on all of the information available about these wells from the state-owned companies – China National Offshore Oil Co. (CNOOC), CNPC, PetroChina, and China United CBM.

On Oct. 29 Green Dragon announced a nonbinding preliminary agreement with CNOOC in relation to the drilling that had been carried out on its license area. The company said at the time that it believed it would accrue revenue and reserves from the wells drilled by these companies.

State-owned companies increase drilling

One drilling company is making inroads in CBM wells in China. Greka Drilling signed a series of contracts in the first half of 2013. On June 20, the company was awarded a second contract from Huabei Oilfield, a subsidiary of CNPC, to drill wells in the Anze CBM Project in Shanxi, China. The target coal seams are at depths from 1,000 m to 1,400 m (3,300 ft to 4,592 ft). Around 110 vertical and directional wells will be drilled in 2013 by CNPC and Greka. A total of 300 wells are planned for the project.

Huabei Jincheng contracted Greka to drill at its Jincheng block in Shanxi Province. Currently, a four-well directional drilling program is being drilled. One well that the drilling company completed is on production and being evaluated.

Sinopec’s Huadong CBM contracted the company for a one-year program to drill 50 wells at Jixian, Shanxi Province. Sinopec Huadong CBM has a 3,000-well program. About 600 wells in total are planned for this year. Greka has two rigs operating and expects to continue the drilling program subject to agreement with the client on drilling locations.

Sinopec’s Huabei (Petroking) project has plans for a 50-well program during the current exploration phase for unconventional oil within the Xunyi block, Shanxi. Greka is under contract to drill 100 wells subject to successful drilling of the first 20 drilled across the Sinopec Huabei acreage, including the Xunyi block. The company also has two rigs currently drilling under this program. The first horizontal well was spudded Aug. 1 in cooperation with Sinopec engineers.

US CBM loses out to shale gas

According to the US Energy Information Administration, CBM production steadily declined from 2008 to 2011, which corresponds to the increase in shale gas production. CBM went from 55.5 MMcm (1.96 Bcf) in 2008 to 49.8 MMcm (1.76 Bcf) in 2011.

The top five CBM-producing states in 2011 were Colorado, 14.6 Bcm (516 Bcf); Wyoming, 14.3 Bcm (506 Bcf); New Mexico, 10.6 Bcm (374 Bcf); Virginia, 2.83 Bcm (100 Bcf); and Alabama, 2.78 Bcm (98 Bcf).

Consol Energy has been the leading producer of CBM in the Appalachian basin since the 1980s. In 2Q 2013 its total production was 589 MMcm (20.8 Bcf), which is 7% lower than the 631.5 MMcm (22.3 Bcf) produced in 2Q 2012. The company reduced its focus on CBM drilling and has been shifting rigs and capital toward higher potential return Marcellus and Utica drilling prospects.

Cementing inflatable packers adds pay to Australian CSG wells

Zonal isolation and minimizing loss of productive coalseam exposure are significant challenges faced by Australia’s coalseam gas (CSG) producers. In two of the country’s larger CSG states, operators are achieving both with a novel technique that inflates specialized annular casing packers (ACP) with cement.

In Queensland, where most of the country’s CSG is produced, operators in the Surat and Bowen basins are using Weatherford’s BullDog inflatable ACP and stage cementing tools to avoid covering valuable pay exposure while providing long-term isolation. More than 1,000 successful zonal isolations have been completed to date.

The exposure challenge stems from isolation regulations that require cement to be placed to a predetermined depth below the top coal seam. To meet this requirement, a 1.2-m (4-ft) conventional packer element is set at a predetermined depth below the top coal seam, further covering the producing zone, providing a platform for cementing above the zone to the surface, and preventing cement contamination of the coal seam. This ensures that there is complete well integrity and protects the formation and above.

Inflating the packer conserves the 1.2 m of exposure to coalseam pay that would otherwise be lost. In doing so, it achieves the primary objective of long-term zonal isolation.

Installed as an integral part of the casing, the BullDog ACP system is typically placed at a predetermined depth below the upper coal seam prior to cementing the casing. Full inflation with cement puts the packer element in contact with the borehole. This immediately isolates the lower coal seam while allowing the casing string above it to be cemented through a casing-cementing tool.

Weatherford’s Micro-Seal swellable elastomer technology is often used to enhance zonal isolation by preventing gas flow that can occur during production due to the development of a microannulus between the cement and casing interface, which is common during the life of the well.

Success in the Australian wells provides a solution to the regulatory challenge that satisfies the zonal isolation objectives without compromising the well’s productivity.