Zhang Mi, chairman and president of Honghua Group, spoke with Drilling Contractor at the 2013 OTC. He noted that while his company’s current focus is on the US onshore market, he believes Honghua can eventually deploy the same technologies in China once unconventionals development expands in that country.

Honghua Group and its US subsidiary Honghua America are developing a next-generation onshore rig for shale drilling called the US #1; a prototype is under construction at the company’s Houston factory and scheduled for completion in late 2013 or early 2014. Further, the company is working with Baker Hughes to field test Honghua’s 6,000-hp hydraulic fracturing pump in Texas. Speaking during an exclusive interview with Drilling Contractor at the 2013 OTC, Zhang Mi, chairman and president of Honghua Group, noted that such technologies are examples of his company’s focus on the US onshore market; yet, they are also technologies that he believes Honghua can eventually deploy in China once development of unconventionals expands in that country.

The US #1 rig has been designed to be highly mechanized and highly automated, Mr Zhang explained, and one technology that will be incorporated is Honghua’s new direct-drive triplex mud pump. The pump is driven by a top-mounted AC motor that powers the pinion shaft. This removes the intermediate transmission (e.g. belt, chain and gear), reducing maintenance and vibrations and lowering noise.  A smaller environmental footprint is another key feature of the US #1 rig. Mr Zhang noted that it has been designed to be powered with natural gas and LNG, and perhaps even grid power in some cases. “If (US #1 is) successful, it will be an example for Honghua’s next-generation rigs.”

The company also continues work on its 6,000-hp frac pump, introduced at last year’s OTC. Honghua is now working with Baker Hughes to bring this technology to the US market for field-testing, Mr Zhang said. “Once the field tests are complete, I believe it will also bring about step-changes for shale drilling in the US.” Field-testing will likely take place in Texas around August, he said.

Honghua Group’s triplex direct-drive pump, exhibited at the 2013 OTC, reduces maintenance, increases service life and reduces noise emissions and vibrations. The pump will be integrated into Honghua’s next-generation rig, the US #1.

Looking toward the Chinese market, Mr Zhang explained that although there are approximately 2,000 land drilling rigs operating in China, most of them are older mechanical or SCR-style rigs. “There is a significant need for renewal of the fleet,” he said, adding that he believes innovations such as Honghua’s direct-drive triplex pump will be able to impact the Chinese market once it’s proven in the US. “The locations in China where there’s potential for shale gas are not like Texas, where you have wide spaces where you can build wellsites. In China, they are located in mountainous regions, so access to shale gas reserves is more difficult. Being able to reduce the footprint is especially important.”

Although onshore rigs and technology remain at the core of Honghua’s business, the company is also pushing ahead with its entry into the offshore rig construction segment, with the large-capacity Honghai mobile crane the centerpiece technology driving their efforts. “When our Honghai crane is completed with a lifting capacity of 22,000 metric tons, you can construct the entire platform on land and then transport it offshore as a complete piece… We believe this will be a first in the world,” Mr Zhang said.

Construction of the crane began in October 2012 near Shanghai. Once completed, Honghua plans to use it for large-scale and simultaneous production of five to 10 offshore rigs, he said. The crane will be completed by the end of 2013 or Q1 2014, and Mr Zhang noted that discussions for offshore rig orders are ongoing, primarily with non-Chinese companies.

Marathon Oil forecasts its production from US resource plays will increase by 150% from Q3 2011 to Q4 2013, Bryan Roy, vice president – drilling & completions for Marathon Oil, said at the 2013 IADC Drilling Onshore Conference.

Marathon Oil has determined that it may drill more than 3,000 wells in its Eagle Ford acreage, up from an earlier estimate of approximately 1,200. In fact, the company expects production from its US resource assets, which also include the Bakken and the Woodford, to increase by 150% from Q3 2011 to Q4 2013, Bryan Roy, vice president – drilling & completions for Marathon Oil, said. “When you talk about shale and moving the needle for a company that is producing between 400,000 and 450,000 bbls/day, that is substantial,” Mr Roy said during a presentation at the 2013 IADC Drilling Onshore Conference on 16 May in Houston.

For Marathon, the impact that US resource plays are having on the company’s portfolio is significant. As an example, its US business once provided capital for large expenditures overseas, but that pendulum has swung in the opposite direction due to the growth in US unconventionals. “Now, a lot of Equatorial Guinea and Norway production is funding a lot of capital in the US,” Mr Roy said. “We are targeting 5% to 7% average growth rate (in production) across the world.”

Marathon currently has 16 rigs working in the Eagle Ford and expects to spend nearly $2 billion in that play this year, according to Mr Roy. “One of the challenges we continue to have is we tend to overspend our capital because we keep drilling wells so fast,” he stated. “That will continue to be a problem, I hope, because it’s a mark of efficiency.” The company also continues to study its approach to developing its Eagle Ford acreage, such as optimal well density, lateral lengths and completion techniques. “A lot of pilots in the ground now are already completed … and the science looks good. We spent a lot to get into the Eagle Ford, but it’s looking a lot better than what we thought it was going to be,” he said, referring to the increase in the number of estimated wells.

Outside of the US, Marathon also continues an aggressive exploration program in Kurdistan in northern Iraq, where the company made entry in 2010. It currently has two rigs drilling in the Harir and Safen blocks, which Marathon believes have “the potential for the largest unexplored basins in the world,” Mr Roy said. “We are very interested to see how productive the wells could be.”

The region does come with significant operational challenges, however, from security issues to high H₂S concentrations in the ground. In fact, some zones can carry up to 22% H₂S combined with 13% CO₂, Mr Roy said, making it a challenge to complete and make long-term production adequate. Other challenges include lost circulation and issues with primary cement jobs and directional control. Beyond that, “we still have significant issues relative to emergency response plans and evacuations that could be required,” he noted.

Dual-fuel kits on drilling rigs provide flexibility and carry a lower conversion cost than LNG-dedicated rigs, Bryant Dear, Noble Energy, said at 2013 IADC Drilling Onshore Conference in Houston on 16 May. However, the cost savings for dual-fuel engines are still to be determined, he added.

After a pilot program initiated in early 2011 to compare the use of LNG versus diesel to power drilling rigs, Noble Energy now has four dual-fuel rigs and one LNG-dedicated rig operating in the DJ Basin and the Marcellus. “It’s going to cost you to convert your rig to LNG. There’s a price tag to it, but we see that price tag being well worth it,” Sean Howley, senior business analyst for Noble Energy, said in a presentation at the 2013 IADC Drilling Onshore Conference in Houston on 16 May. “We actually think it will pay off in two years,” he said of the LNG-dedicated rigs. “After that, it’s all savings.”

During the pilot program, Noble Energy gathered 12 months of operating data on three rigs – two that were LNG-dedicated  and one running on diesel. The goal was to demonstrate the operational and economic viability of displacing diesel and powering the majority of Noble’s rigs with LNG, Bryant Dear, a co-presenter with Mr Howley, explained. Mr Dear is a drilling engineer in the DJ Basin for Noble Energy.

After evaluating the use of field gas and CNG, Noble decided that LNG would be the best option due to its higher energy density and consistent quality. There were also multiple options for turnkey providers, Mr Howley explained.

Sean Howley, Noble Energy, said at the conference on 16 May that his company is committed to using LNG for more operations going forward. Noble is currently building an LNG plant in Colorado to provide a closer fuel source.

Currently Noble has four fit-for-purpose dual-fuel rigs –Rigs 828 and 829 in the DJ Basin and Rigs 542 and 543 in the Marcellus, all from Precision Drilling. Although the cost savings that can be achieved for dual-fuel rigs are still “to be determined,” Mr Dear said, that is offset by a much lower conversion cost than LNG-dedicated rigs. Each of the four dual-fuel rigs is equipped with a GTI Altronics bi-fuel kit set up on three Caterpillar engines, he explained. “It’s too early to tell what our (fuel substitution) rates are, but we’re working to increase those as technology gets better and these systems get better… One thing we do know is you’ve got to displace as much diesel as possible (to achieve maximum cost savings).”

Mr Howley noted that Noble Energy’s commitment to LNG is such that the company is building an LNG plant in Weld County, Colo. “That’s going to bring our price much further down; it’s going to be an amazing option,” he continued. Not only does Noble plan to build a balanced portfolio of LNG-dedicated rigs and dual-fuel rigs, but the company is already expanding LNG applications to its frac fleet as well.

Noble currently has one frac engine running on a mix of LNG and diesel in the DJ Basin and plans to have another switch to dual fuels by June. “If we don’t need (the LNG) on a frac job, we can roll it over to one of our rigs. When we don’t need it on the rig, we can roll it over to a frac job. It provides some really nice synergies for us,” Mr Howley said.

Although Statoil has deep roots as a Norway-based offshore operator, the company is now finding the US onshore business to be at the heart of its E&P strategy. With core operations in the Bakken, Marcellus and Eagle Ford, the US onshore business has become the fastest-growing sector for Statoil within the past three years, Stephen Bull, vice president – commercial North America, D&P, said. Mr Bull discussed how the company landed in the US onshore business and how it has become part of Statoil’s corporate strategy in a presentation at the IADC Drilling Onshore Conference on 16 May in Houston.

Statoil’s goal is to produce 2.5 million bbls/day by 2020, and US unconventionals is at the heart of its E&P strategy to accomplish that goal, Stephen Bull, vice president – commercial North America, D&P for Statoil said.

Statoil is a historically deepwater-oriented company, Mr Bull said; approximately 1.5 million bbl of its 2 million-plus bbl daily production come from Norway, and the remaining comes from Angola, Azerbaijan and Brazil. However, “the fastest-growing area is by far North America,” Mr Bull stated. In fact, the US unconventional business is now at the center of Statoil’s goal to produce 2.5 million bbl/day by 2020. This E&P strategy consists of three elements: a strong management system, technology, and a long-term commitment to the communities in which it operates.

The first element – a robust management model – is applied through the whole company, Mr Bull emphasized. For example, when Statoil entered the US onshore business, the company created an operations support team to analyze performance metrics to enhance its understanding of the business. “That team is developing a cross-functional collaboration,” he said. “We looked at the best wells in the Eagle Ford. We looked at other operators, benchmarked them completely across the board, gave them rational reviews and looked at what are the best operations.” Based on those findings, Statoil saw the potential for 45% to 50% improvement in performance. “The first few wells that we have drilled in the Eagle Ford have been fairly close to what we want to achieve.”

Statoil also aims to apply its knowledge and experience in hostile recovery techniques used in the Norwegian sector to the US onshore. In Norway, the company has achieved more than 50% recovery rates in some fields and some as high as 75%. While acknowledging that the US plays behave differently and have different permeabilities, “we want to apply that (experience) to the US onshore” to increase recovery rates, Mr Bull said.

In the Williston Basin, Statoil has been swapping out its older rigs for walking rigs that can reduce drilling and skid times and is using dual fuel technologies when possible, Mr Bull said. Further, the company has 700 miles of oil, freshwater and saltwater pipelines in the Williston Basin that help to “reduce thousands of trucks on the road when we are doing our frac jobs,” he continued. Statoil also continues to develop new technologies and solutions for unconventionals at its research center in Houston.

Part of Statoil’s long-term perspective is its investment in industry collaboration and commitment to the communities in which it operates. Mr Bull believes that his company’s efforts are apparent in three ways: direct financial support, participation on local boards and volunteer efforts. “Employees serve on school boards, hospital boards and volunteer efforts as well, from trash pickups to cook-offs,” he noted.

Besides communication and leadership knowledge and understanding, Mr Bull noted that there’s also an X factor to Statoil’s E&P strategy. “You can’t just come in here and talk about processes and ‘you must follow this,’ ” he stated. “We need some creativity in there, and you need a just-do-it attitude and an entrepreneurial feeling you get in the US onshore. We don’t want to lose that.”

To help operators extract more petroleum from process water and reduce the need to use fresh water in the fracturing operations, OriginOil has developed a chemical-free water treatment and separation technology. The CLEAN-FRAC mobile laboratory recently made a stop in Houston during a tour that started in Los Angeles. Riggs Eckelberry, president & CEO of OriginOil, speaks with Drilling Contractor associate editor Joanne Liou in a DC-exclusive video about the technology, which completed its first field test at an oil well near Bakersfield, Calif.

Vinay Mehta, vice president of technical excellence & innovation for Fairmount Minerals, speaks with Drilling Contractor associate editor Katherine Scott about the opening of the Santrol Technology Center in Sugar Land, Texas. The new R&D center expands the company’s proppant portfolio for hydraulic fracturing to improve reservoir conductivity and maximize oil and gas production. Equipment in the facility includes an HPHT viscometer, a helium pycnometer, a three-minute hot tensile tester, a dynamic mechanical analyzer, and a raman-infrared spectroscope. The technology center is run by Santrol, a part of the Fairmount Minerals group offering environmentally responsible proppants for a range of applications.

The change between water samples taken before and after treatment with NOV’s AQUA-VES Mobile Water-Treatment system, which uses a membrane separation technology, can be seen. The system allows operators to reuse water for hydraulic fracturing.

National Oilwell Varco (NOV) FluidControl has introduced a mobile water-treatment system for hydraulic fracturing operations that uses a membrane separation technology relying on vibration rather than flow-rate technologies or chemicals.

The AQUA-VES Mobile Water-Treatment System, recently deployed in West Texas, removes all suspended solids, oil, grease, bacteria and oxidized iron from the water, breaking it down to a brine that can be reused for fracturing, said Drue Ann Whittecar, business development manager, NOV Water Services. The system can process between 2,500 bbls and 10,000 bbls of liquid waste a day. “After it is processed, the water is very clear and clean, opening up opportunities for operators to source less water on the front side of a fracturing operation and dispose less water on the backside,” she said.

The system, developed by NOV in conjunction with a third party, is transported on a 53-ft trailer and includes a pump skid and two membrane towers that remove suspended solids, total petroleum hydrocarbons (TPH), bacteria and oxidized metals from water. A combination of micro- and nano-filtration are used to extract contamination from water. The design allows the membrane to remain clean, allowing for unobstructed filtration of the flow-through water, Ms Whittecar explained. The system can accommodate a wide range of membrane sizes, from micro-filters to reverse osmosis, making it applicable for a variety of operating environments.

“Water management is not a one-size-fits-all situation but varies by shale play,” she said. “Water that comes into the system will be different in every play, as will the water requirements for drilling and completions operations. The AQUA-VES system is particularly suited to West Texas, where it is difficult to source water due to demand from the local population. We also believe AQUA-VES will be a good fit for cleaning solids out of salt water-based mud in the Bakken play, where operators need brine for hydraulic fracturing, and in the Marcellus, where used water must be shipped to Ohio for disposal.”

The self-cleaning membrane technology requires minimal pre-treatment due to the high shearing energy at the membrane surface and near the pores. It delivers throughput rates five to 15 times higher than conventional units, and uses less energy than cross-flow filtration systems that require high flow rates to keep the filters clean, she noted. Membrane cleaning can be done on the surface, without the unit being disassembled. The Teflon coating is resistant to acids, solvents and other cleaning compounds.

The company is building three more systems for deployment to shale plays and is looking at developing other applications as well, including one for offshore use, Ms Whittecar added. Regulations allow salt water to be discharged, but any water containing solids must be transported back to shore for disposal.

AQUA-VES is a trademarked term of NOV.

Oil produced in Eagle Ford has increased from 5 million bbls in 2010 to more than 40 million bbls in 2011, according to data from the Texas Railroad Commission. Condensate production has increased from 6 million bbls in 2010 to more than 24 million in 2011. As of October 2012, crude production topped 112 million bbls, while condensate production was estimated to be approximately 24 million bbls.

The 2012 Eagle Ford Shale estimated total economic output impact was more than $61 billion in South Texas, which is more than double the economic impact the year before – $25 billion in 2011, according to a study by the Center for Community and Business Research at the University of Texas at San Antonio Institute for Economic Development. Communities throughout South Texas are benefitting from significant economic impacts from natural gas and oil development in the Eagle Ford Shale, including benefits from related infrastructure and ancillary industries spurred by energy development.

In 2012, impacts were assessed for a 20-county region, which includes the 14 counties directly involved in natural gas and oil production, as well as the six surrounding counties indirectly supporting production. Over the last four years since Petrohawk Energy Corp drilled the first well in Eagle Ford Shale, natural gas and oil production has consistently exceeded year-over-year expectations. In 2011, given continued low natural gas prices and high oil prices, operators shifted focus to zones rich in oil, natural gas liquids and condensate. As a result, in 2012, natural gas production in the shale experienced a slight decline, and oil production increased significantly – from 5 million bbls in 2010, to approximately 128 million bbls in 2012.

Estimated economic impacts for 2012 are based on annual natural gas and oil production data from the Texas Railroad Commission, pricing information from the Energy Information Administration, estimated drilling and completion costs, and estimated royalty and lease payments.

The economic benefits extend beyond the well pad and throughout the communities at large:

• Lease payments – Reported to range widely and as high as $5,000/acre, lease payments provided approximately $2.2 million in revenues and $1.3 million in gross regional product.
• Royalties – Royalties serve as an important source of income to the owners of mineral-producing properties. Royalty payments generated $185.5 million in total output impact and supported close to 1,512 jobs.
• Sales taxes – Sales taxes continued to rise in 2012, creating a wave of revenue for local communities. From Q2 2009 to Q2 2012, amounts subject to sales tax in the 14 counties had grown from $751.9 million to $1.2 billion, a 68.2% increase in three years. McMullen County showed the most significant increase between the Q2 2009 and Q2 2012 at 1,243.7%.
• Right-of-way payments – Right-of-way payments are those made by a pipeline operator to a landowner for the use of a strip of land that runs over and around a pipeline carrying natural gas, crude or other hydrocarbons. In 2012, $192 million right-of-way payments were made resulting in an economic output of $5.8 million and $3.5 million in total gross regional product. These payments also supported 47 full-time jobs.

Analysts, investors and industry experts agree that the Eagle Ford’s high-reservoir quality, ideal location to markets, existing and planned infrastructure, and proximity to the Gulf Coast all make the it one of the world’s premier natural gas and oil plays in 2012 and beyond. Eagle Ford Shale by 2022 under moderate estimates for the 20 counties is expected to:

• Account for $89.5 billion in total economic output (or revenue);
• Support 127,919 full-time jobs;
• Pay $6.5 billion in salaries and benefits for workers;
• Contribute $41.8 billion in gross regional product (value added);
• Add $2.2 billion in state revenues; and
• Provide $2.1 billion in local government revenues.

The Schramm T500XD is specifically designed for horizontal and directional drilling to a total depth of 15,000 ft or more. It is currently headed to the Marcellus and Utica shale.

Schramm has launched its T500XD Telemast 500,000 lb hoist capacity drill rig currently headed to the Marcellus and Utica shales. The rig has a full 360° walking portability for fast moves from hole to hole without the traditional limits of two axis pad mounted designs.

The T500XD also offers a full communication interface connectivity to third-party data acquisition providers that utilize the internet or dedicated satellite communications systems to remote operation centers in multiple locations.

Specifically designed for horizontal and directional drilling to a total depth of 15,000 ft or more, the Schramm T500XD can control weight on bit without relying on drill collars and gross string weight alone.

It offers 35,000 ft-lbs of top head torque, third-party directional steering interface and 80,000 lbs of hydraulic pulldown capacity.

This rig includes an integral LoadSafe XD system that can handle 24 in.-diameter Range III tubulars weighing up to 10,000 lbs. Drill pipe is racked in the horizontal position for easy loading and offloading, thereby improving operator safety.

Telemast and LoadSafe are registered trademarks of Schramm.

E&P will take up the biggest portion of Petrobras’ 2013-2017 Business and Management Plan budget, at US $147.5 billion, or 62% of the total $236.7 billion.

Petrobras has announced a US $236.7 billion budget under a 2013-2017 Business & Management Plan (2013-17 BP) that has been approved by the company’s Board of Directors. The largest share of the total – an estimated 62%, or $147.5 billion – is earmarked for E&P.

Continuing the 2012-2016 BP, the new plan was determined based on four principles:

• Maintaining the same production targets for oil and natural gas;

• No additional projects, except those related to oil and natural gas exploration and production in Brazil;

• Incorporating the results of the structural support programs (PROCOP, PROEF, PRCPoço and INFRALOG); and

• Expanding the scope of the divestment program PRODESIN.

The 2013-17 BP maintains the project management practice of separating projects into four phases according to their maturity. The portfolio of projects under implementation amounts to $207.1 billion and includes all Phase IV projects that have been contracted and all E&P projects in Brazil. The portfolio under evaluation, with $29.6 billion, encompasses projects of other business areas that are currently in Phase I (opportunity identification), II (conceptual project) and III (basic project). These projects must have their technical and economic feasibility confirmed (Phase III approval) before proceeding to the implementation phase.

The analysis of the 2013-17 BP portfolio resulted in the maintenance of 2012-16 BP projects, without including or excluding new projects in the portfolio under implementation. Exceptions were E&P project exceptions in Brazil, where there were inclusions and exclusions, as well as accelerations and postponements of projects, to meet planned production goals.

BP management actions

The 2013-2017 BP also continues with supporting programs initiated in 2012 and incorporates five new programs:

• Campos Basin Operational Efficiency Improvement Program (Proef) – Increases reliability of achieving the oil production curve by improving operational efficiency and integrity of older Campos Basin production systems and reducing risks of efficiency losses of newer production systems;

• Operating Expenses Optimization Program (Procop) – Increases cash flow generation and productivity and strengthens management model geared toward cost excellence, with operating expenses savings target of R$32 billion from 2013 to 2016.

• Divestment Program (Prodesin) – Contributes to financing the plan through the sale of assets in Brazil and overseas with cash proceeds estimated at US $9.9 billion in 2013, largely;

• Logistical Infrastructure Optimization Program (Infralog) – Integrated planning, monitoring and management of projects and actions to meet Petrobras’ logistical infrastructure needs by 2020. By seeking simpler logistical solutions and capturing synergies among the company’s business areas, investment reductions have been incorporated into the 2013-17 BP, notably US $2.6 billion in E&P;

• Well Cost Reduction Program (PRC-Poço) – Reduces well costs (CAPEX) optimizes project scopes and productivity gains through 23 initiatives due to the significant increase of the drilling rig fleet under operation and the relevance of well construction CAPEX in the E&P budget from 2013 to 2017 (38%). Identified gains of US $1.4 billion, already incorporated into the 2013-17 BP, from initiatives related to decreasing well construction time and optimizing operational sequencing.

Oil and natural gas production

Oil and NGL (natural gas liquids) production target in Brazil is 2.5 million bbl/day in 2016, 2.75 million bbl/day in 2017 and 4.2 million bbl/day in 2020. As in 2012, the target for 2013 is to maintain production in line with 2011 levels (+/- 2%). From 2013 to 2015, 11 new production units will go on-stream, representing a capacity increase of 1.45 million bbl/day for Petrobras. In 2016 and 2017, most pre-salt and Transfer of Rights projects are expected to start up, leading to production growth acceleration. Pre-salt is expected to account for 35% of total production in 2017.

The production target for oil, NGL and natural gas in Brazil is 3.0 million bbl/day of oil equivalent for 2016, 3.4 million bbl/day of oil equivalent for 2017 and 5.2 million bbl/day of oil equivalent for 2020.

Investments

The E&P segment in Brazil will invest US $147.5 billion, which represents an increase of US $15.9 billion from the 2012-16 BP, mainly due to the inclusion of 2017 investments that reflect the acceleration of planned production between 2016 and 2020. Of the investment total, 73% will be allocated to production development, 16% to exploration and 11% to infrastructure. Pre-salt and Transfer of Rights investments correspond to 68% of the total amount invested in production development.

In addition to these investments, the execution of projects during the 2013-17 BP will demand US $39.7 billion from Petrobras partners for E&P activities in Brazil.

Financing

In evaluating the capacity to finance the plan, the company based cash flow generation on a long-term Brent price of US $100/bbl and an exchange rate ranging between R$2.00/US$ and R$1.85/US$.

The resources necessary to finance projects under implementation will come from operating cash flow generation (US $164.7 billion), use of surplus cash (US$10.7 billion), divestment and financial restructuring (US $9.9 billion) and debt (US $61.3 billion gross, US $21.4 billion net).

Petrobras expects to experience higher annual investment combined with less operating cash flow generation in 2013; however, this situation will be reverted during the Business Plan period, with free cash flow before dividends becoming positive by 2015.

The increase of cash flow generation due to production growth and investments maturation will reduce the need for financing during 2013-17.

Financial leverage will not exceed 35%, keeping within the target of 25% to 35%.