By Dustin Bleizeffer

Wyoming is set to implement new rules forcing the oil and gas industry to reveal such information on Sept. 15.

While the Wyoming Oil and Gas Conservation Commission doesn’t plan to make special efforts to compile and present the information to the public, agency officials say the information will be readily available.

Operators must disclose the information within regular permitting, sundry and other documentation they submit to the agency. The documentation is listed on a well-by-well basis on the commission’s website (wogcc.state.wy.us).

“I think if there’s an incident, people should have a better feel for what went into the wells,” said commission supervisor Tom Doll. “We’ll see exactly what they pumped into the well. Further, they have to report what comes out of the well after they’ve completed the (well stimulations).“

the rest of the story …

Wednesday, September 1st is the day oil and gas interests will be on hand with State lands officials for a roundtable discussion of the revised standard lease forms for oil and gas interests on Wyoming public land.

Officials hope the meeting will clarify ambiguity regarding bonding, royalties, valuation and other matters concerning the first revision of the state oil and gas lease form in 20 years. The document is available on the Wyoming Office of State Lands and Investments website, slf-web.state.wy.us.

The State is not required to hold a public hearing on the changes, but Harold Kemp, assistant director of the state’s mineral leasing and royalty compliance division, said officials want to hear comments and suggestions from stakeholders. “This newly proposed lease form will bring considerably more simplicity in terms of details what the state’s expectations are. We want people to be able to discuss those changes with us and provide concerns verbally or in writing, and we will provide consideration on this end.”

Wednesday’s meeting begins at 9 a.m. and if you are interested in attending the roundtable discussion, contact Donna Bracht at dbrach@wyo.gov.

According to Kemp, a final draft of the oil and gas leasing form will be prepared to present to the state land board in October for approval.

For years, the Bureau of land Management has conducted oil and gas lease sales in which Wyoming accepts bonus bid payments for the right to develop oil and natural gas on state lands. Three  competitive lease auctions have been conducted so far this year, including the most recent one last month which generated more than $42 million in bids for 287 parcels, in large part because of the surging interest in the Niobrara oil play in southeast Wyoming. The next scheduled auction is November 3.

The Ruby will bring an additional capacity of 1.5 billion cubic feet of gas per day, and natural gas producers will, for a time, have more pipe than production, according to the Wyoming Pipeline Authority. Nearly three quarters of the pipeline capacity is already under contract, and the rest will be marketed, according to officials, with the hopes that the remaining capacity could also be spoken for before the expected completion in the first quarter of next year.

For several years the Rockies have remained under export capacity restraints when it came to moving natural gas to other markets, which meant states like Wyoming received less revenue. The Ruby pipeline, it was thought, would help alleviate the situation by connecting Rockies gas to the northern California market, where the industry believed a major drop in the supply of Canadian natural gas would occur. 

However, the recent surge in natural gas production from shale gas plays like the Marcellus in the eastern United States has slowed the flow of Canadian gas to the Midwest. That translates into plenty of Canadian gas available for the U.S. West Coast market, at least for now. So, there will be competition between gas from the Rockies and gas from our neighbors to the north.

Still, West Coast utilities are adding more natural gas to their energy portfolios in order to meet state carbon reduction goals and that is expected to maintain demand from the competing supply regions.

The changes resulted in a net increase of total core areas protected of an estimated 400,000 acres, Freudenthal said. “There was acreage deleted and there was acreage added. I think that it is a net plus in terms of the acreage that is now protected in the core area,” Freudenthal said Wednesday during a media conference.

Earlier this year, the U.S. Department of Interior determined that the sage grouse qualified for protection under the Endangered Species Act — including its range in Wyoming — but precluded listing the bird because of higher-priority listing commitments.

Wyoming’s core areas policy requires that developers of new activities must first demonstrate how sage grouse populations will not be diminished.

Regarding wind,  the Governor said that while exceptions will be considered under the policy for virtually all types of activities, there are no exceptions to the restriction of new wind energy development. Freudenthal noted that the U.S. Fish and Wildlife Service, on two occasions, indicated that wind energy development is “incompatible” with core area protection. However, that will not prevent the state from revisiting the issue, particularly once new information is available from a coordinated effort to measure wind energy’s impact on sage grouse outside the core areas.

the rest of the story …

Multi-Stage Plunger Lifts Offer

INTRODUCTION

Plunger lifts are effectively used primarily in natural gas drilling, and particularly appropriate for wells in which natural depletion has fallen below critical flow rate, or for wells with high accumulations of solids such as sand, salt, coal fines, paraffin and scale. Because it is easy to install and economical, a plunger lift is a popular method of deliquification for wells with high gas and low liquids.

But what about particularly deep wells, or wells with low gas and high liquids, or low gas-to-liquid ratio such as gassy oil wells? As the ratio of liquids increases, more artificial lift is needed to get liquids out of a well. Typically, a pump jack or soaping would be used in these situations. However, another alternative exists that is more economical and has produced solid results.

In wells with low gas to liquid ratio (GLR), or wells that are seeing only marginal results from a conventional plunger lift system, a multi-stage tool can be used to increase production. Intended to create multiple plunger lift systems in one well, this design enables the liquid load to be lifted in stages. As such, it allows the well to utilize its own energy to efficiently remove even large accumulations of liquids, even the heavy kind.

HOW A MULTI-STAGE TOOL INCREASES PLUNGER LIFT EFFECTIVENESS

The multi-stage tool is placed by wireline roughly 40-70% of the way down the tubing above a plunger lift system installation, which is typically comprised of a bottom home bumper spring and a plunger above it. Then a second plunger is set on top of the tool.

The system is operated like a conventional plunger lift. During the first sales cycle, the lower plunger carries fluids up the tubing and delivers them to the tool. The fluids flow through the tool and are held above it by gas flow. Upon shut-in, the ball check in the tool engages, retaining the fluids until the upper plunger falls from the surface, settles through the liquids and lands at the tool. Simultaneously, the lower plunger falls back to the bottom.

During the next sales cycle, the upper plunger delivers its fluids to the surface, while the lower plunger delivers more fluids to the tool. Both plungers work in tandem in subsequent cycles. This way, the multi-stage tool acts like an intermediary standing valve. This process lifts smaller and more frequent liquid loads in stages, allowing the well to more efficiently utilize its own energy to remove liquids and increase productivity.

MULTI-STAGE PLUNGER LIFT: AN EASY AND ECONOMICAL ALTERNATIVE TO PUMP JACKS

The ‘nodding donkeys’ visible at countless well sites demonstrate the popularity of pump jacks as an artificial lift method. Pump jacks (also known as sucker rod pumps, beam pumping units and other names) are typically powered by a fossil fuel or an electric motor. They require a large up-front investment in equipment and installation, and maintenance costs can be high.

A multi-stage lift system typically costs roughly one-tenth that of a pump jack. There is no large, expensive equipment required to operate a plunger lift system. Unlike a pump jack, it requires no power or fuel source because it is an entirely mechanical system that utilizes the well’s own energy to operate.

Overall, a multi-stage plunger lift system is much less expensive to install, operate and maintain over the life of a well.

A TALE OF TWO WELLS

Multi-stage plunger lift is being used successfully in wells in the DJ Basin and central Alberta, as well as other regions of North America. Here are two examples of wells that went from being pump jack candidates to multi-stage plunger lift success stories.

Well A - This well site was frequently loading up and no longer able to lift fluids on its own. Initially, a plunger lift system was installed, with the bottom hole bumper spring set at 8,169 feet. The plunger cycled, but because of the large amount of liquid, long shut-in times were required. By the time the plunger was able to run, the tubing pressure was more than 800 psi, which knocked down the separator. When able to cycle, the well produced roughly 17 mcf/day of gas and 12.6 bbl/day. A pump jack installation was considered, but the cost was prohibitive given the marginal production.

The multi-stage tool was installed at a cost of approximately $4,000, which included the existing equipment, the tool and a second plunger. The tool was set at 4,872 feet, with a dual-pad flow-thru (by-pass) plunger below it and a padded plunger above it. The tubing pressure was 1,460 psi, and the casing pressure was 1,510 psi.

After a couple cycles, the pressures lowered to the point where the separator was able to function and constant production was achieved. The cycle times were fine tuned, and the well was able to produce 106 mcf/day of gas and 37.7 bbl/day of oil. After one month, production leveled out and remained at 124 mcf/day of gas and 12.6 bbl/day of oil.

Well A Statistics

	Gas Production (mcf/day)	Oil Production (bbl/day)
Before Stage Tool	17	12.6
After Stage Tool	124	12.6

Well B had similar initial production issues. In addition, it was producing significant frac’ing sand and wax. The bumper spring was set at approximately 8,136 feet. The starting tubing pressure was 200 psi, and the casing pressure was 1,000 psi. Because of the amount of fluid, wax and sand the well was producing, the plunger would not cycle consistently, and the well was shut-in the majority of the time. Pump jack installation and chemical injections were being explored as potential methods to both stabilize and maximize production.

Instead, a multi-stage tool was installed at approximately 5,085 feet, with a solid flow-thru (by-pass) plunger below it and a solid ring sand plunger above. By this time, the well’s tubing pressure had increased to 250 psi, and the casing pressure to 1,200 psi. During the first few cycles, the sand production was challenging. As the casing pressure came down, the well produced more and more sand, causing the bottom plunger to stop cycling and the top plunger to wax off.

After simply pulling the tool by wireline and cleaning the tubing, the sand production decreased. The plungers were able to cycle regularly, keeping the tubing clean and prohibiting wax build-up. The initial production was extremely high for a typical plunger lift system at 70 mcf/day and 37.7 bbl/day of oil. The well’s production then slowed to its current rate of 42 mcf/day and 8.8 bbl/day.

Well B Statistics

CONCLUSION

A multi-stage plunger lift system is a reliable form of artificial lift that can produce significant production increases, while also being easy to operate and much less expensive to install and maintain compared to a pump jack and other common artificial lift methods. With recent design enhancements and proven successes, the multi-stage plunger lift system is providing producers a cost-effective and easy-to-implement alternative to maximize production in marginal wells and wells with low GLR.

A plunger lift isn’t expected to be successful in wells with a 1:1 gas to fluid ratio. However, with the addition of a multi-stage tool, plunger lift designs are successfully being utilized in wells with these characteristics to produce significant production increases.

For more information, contact information@pcslift.com or visit www.pcslift.com.

By Michelle C. Kales and Amy M. Steinfeld

The concentrated light is typically used to heat a transfer fluid (e.g., water or molten salt), which is then used to generate power using conventional turbine technology.  Projects using a variety of CSP technologies have been built or are currently being proposed and considered throughout the southwest, including Nevada, Arizona and California.  For example, in 2007, Nevada Solar One - a 64 megawatt CSP plant  - was completed in Boulder City, Nevada. The 400-acre plant produces enough energy to power more than 14,000 homes and brings Nevada closer to its renewable energy goal.  It is only the second solar thermal plant built in the United States in more than 16 years, but several other CSP plants are in various stages of planning and development throughout southwest.  The increasing demand for CSP development in the southwest is driven by state-mandated renewable energy portfolio requirements and an abundance of land ideal for solar power generation. 

WATER, A LIMITING FACTOR

Another natural resource, however, is putting the brakes on many CSP projects in these states.  While the sunshine is abundant throughout the southwest, water is not only scarce, but it is heavily regulated.  Although concentrated solar is becoming more efficient as technology improves, producing more power with smaller land area, the most efficient and least expensive type of CSP technology still requires relatively large quantities of water for heat transfer fluid and cooling purposes.  Currently, all operating CSP plants in the United States employ some form of evaporative water cooling.  As with fossil fuel plants, this type of wet-cooling is used to condense steam and much of this water is lost to evaporation.  Because of water scarcity, many pending projects are shifting to new dry-cooling technologies, which can reduce water use by up to 90 percent.  However, dry-cooling is still typically more expensive and can be less efficient when air temperatures are high.

Throughout the southwest, water woes have slowed the pace of solar development.  State resource agencies, local governments, environmental groups and local residents have all voiced opposition to the siting of any solar project in their states that comes with large water demands.  For instance, in California - a state with one of the most aggressive renewable energy portfolio requirements - solar developers have been forced to find new technologies when local water officials refused to sign-off on projects because of water needs. 

In July 2010, NextEra Energy Resources, the developer of a CSP project in California’s Sonoran Desert, agreed to switch to a dry-cooling system after the California Energy Commission (CEC) recommended against using wet cooling.  Likewise, CSP projects being developed on federal land, such as the Ivanpah solar plant in California’s Mojave Desert, plan to use dry-cooling.  In response to concerns by local citizens and state agencies, some solar developers, such as Arizona’s Mohave Sun Power, are considering the viability of using reclaimed water for cooling purposes to avoid expensive dry-cooling. 

STATE ACTION

California has tried to address this and other stumbling blocks to renewable energy development by creating a streamlined certification program for solar projects over 50 megawatts.  This program, administered by the CEC preempts local groundwater ordinances and state water supply assessment requirements for projects falling under the California Environmental Quality Act, which requires development projects to submit documentation of their potential environmental impact. 

Since some local groundwater ordinances limit and highly regulate the extraction of groundwater in the area, and water supply assessments require developers to engage in a lengthy and costly process to demonstrate adequate water supplies for the project, the CEC’s streamlined process appears on its face to avoid difficult water rights issues.  As part of its review process, the CEC thoroughly evaluates water supply and quality issues, and requires that an applicant’s proposed use of water conforms to all state water-related laws and policies.

While the CEC’s official policy provides that it will approve the use of potable water for solar plant cooling purposes only where alternative water supply sources are “environmentally undesirable” or “economically unsound,” in practice the CEC is not currently permitting large-scale CSP projects to use large quantities of potable water.  

LOOKING AHEAD

As conflicts over water increase, other states may follow California’s lead in regulating the use of water for solar projects and in discouraging the use of wet cooling.  In a recent report on the nexus between water and solar, Arizona Senator Jon Kyl recommended that Arizona require CSP plants to be dry-cooled or to use reclaimed water for cooling purposes.  For that reason, solar project developers must have a clear understanding of a property’s water rights, including the reliability of existing water supplies, the existence of any relevant water law restrictions, and the type and quality of water used.  This will assist developers in purchasing or leasing decisions for a site, and help establish a project’s budget, efficiency, and ultimate feasibility.  In the increasingly parched southwest, demonstrating adequate water supplies could be a difficult hurdle in the permitting process for solar energy projects.  By implementing dry-cooling technologies or by using reclaimed water and other non-potable supplies, developers may limit environmental challenges to a project’s water use.  Moreover, knowing a state’s tolerance for water intensive projects up front and planning for water needs in advance of site and technology selection will help minimize delay and unnecessary expense. 

Michelle Kales is a shareholder in Brownstein Hyatt Farber Schreck’s natural resources group. As chairperson of the Renewable Energy practice group she focuses on environmental and energy law, litigation, and land use for a variety of clients, including utilities, energy development companies, residential developers and other real estate developers. As an associate in Brownstein’s water and public lands group, Amy Steinfeld works a broad range of water issues, including legal transactions, litigation, groundwater adjudications and environmental quality projects.

The meetings Aug. 31 in Cheyenne and Sept. 1 in Wheatland and Torrington will be hosted by the Wheatland-based High Plains Economic Development District.

While not much drilling has occured yet, energy companies have obtained dozens of well permits this year and already spend millions acquring oil leases. Industry officials point to horizontal drilling techniques as the means to tap previously inaccessible oil from the Niobrara Shale, and use the example of the Bakken Shale play in North Dakota as a positive example of what an oil boom in Wyoming could bring. North Dakota has just 3.6 percent unemployment and a state surplus of more than $500 million — largely because of oil.

Still, some some people in southeast Wyoming feel nervous, Anja Bendel, executive director of the economic development district, told the AP. “There’s just kind of a fear of, well, what are we looking at? Just kind of a fear of being caught flat-footed,” Bendel said Friday.

Presenters at the meetings will discuss the socio-economic challenges of an oil boom. For example, heavy drilling and related activity could occur well before the drilling would cause a surge in local tax revenue.

The result would be strain on infrastructure, such as roads and bridges, and government, such as police and fire services.

The meetings Sept. 1 are scheduled for 11 a.m. to 1:30 p.m. at the Lincoln Community Complex Gym in Torrington, and from 6-8 p.m. at the Wheatland High School Auditorium.

“From the feedback I’ve been getting, there’s lot of interest,” Bendel said.

A wind power tax subcommittee will meet at Mills City Hall on Aug. 31. The legisltative group is examining how wind energy is taxed.

The panel is currently studying possible changes to the state’s tax structure for wind, which has been a contentious issue for developers, lawmakers and the governor’s office.

The wind industry released a study in June showing Wyoming’s tax structure to be the most onerous of Rocky Mountain states.

This year, lawmakers passed a $1 per megawatt hour wind energy generation tax that takes effect in 2012. The governor’s office says other factors also impact the cost of a project, including capacity, capital cost and federal incentives.

Updated by Staff

Currently, geological storage takes five forms – depleted oil and gas reservoirs; deep saline formations; oil- and gas-rich organic shales; basalts; and unmineable coal seams.

The projects selected are:

- Advanced Resources International – Based in Arlington, VA, it will assess factors influencing CO2 storage capacity and injectivity in Eastern gas shales. It receives $1,345,541 over 24 months.

- Board of Trustees of the Leland Stanford Junior University (Stanford, CA) – Picks up $1,147,612 over 36 months to investigate the feasibility of geological CO2 sequestration in depleted shale gas reservoirs.

- Clemson University – From South Carolina, the university researchers will aim to improve the characterisation of reservoir and caprock compressibility and pressure-dependent permeability with $449,209 over 36 months.

- Colorado School of Mines – Based in Golden, Colorado, it aims to improve the understanding of CO2 trapping mechanisms affected by formation heterogeneity with $510,752 over 36 months.

- Fusion Petroleum Technologies – From Woodlands, Texas, this project picks up $780,185 over 18 months to evaluate experimental design/response surface methods and optimise methods and the operation of a saline formation site.

- Montana State University – A total of $1,599,385 has been awarded to the Bozemon, Montana, project that will develop a biomineralisation based technology for sealing preferential flow pathways.

- New Mexico Institute of Mining and Technology – Based in Socorro, New Mexico, researchers will assess caprock/reservoir interfaces with $399,479 over 36 months.

- Paulsson, Inc – From Brea, California, this study’s objective is to develop a reservoir assessment tool based on robust borehole seismic technology with $1,995,682 over 24 months.

- Trustees of Columbia University in the City of New York – With $1,015,180 they will test and evaluate carbon-14 as a reactive tracer to assess the transportation of CO2 in a basaltic storage reservoir.

- Trustees of Indiana University: Based in Bloomington, Indiana, researchers will receive $401,042 over 36 months to develop a reservoir-scale multi-phase reactive flow model for CO2 plume migration as well as for the dynamic evolution of trapping mechanisms within the Sleipner Project in the North Sea.

- University of Kansas Centre for Research, Inc: A total of $1,598,536 over 36 months will go towards the evaluation of the effectiveness of the volume seismic tool that assesses reservoirs.

- University of Texas at Austin: Will benefit from two projects – the first sees $1,002,633 awarded to develop a prototype of a new computational approach to assess plume migration over 36 months; and the second sees $425,345 go towards complete simulations and experiments for assessing capillary trapping in reservoirs over 24 months.

- University of Wyoming: Benefits from $1,508,198 over 36 months to study the storage of super-critical CO2 and co-contaminants in deep saline formations in Wyoming.

- Yale University: Based in New Haven, Connecticut, it will look at basic questions about the chemical and mechanical processes that must occur in basalt reservoirs with $1,597,187 over 36 months

By Ann Rascalli

The  DOE is injecting $21.3 million over three years into initiatives in the hope of developing the technology and infrastructure for large-scale CO2 storage in different geological formations across the US. They will complement existing activities that include injectivity of CO2 into the reservoir, plume migration and containment by caprock and other trapping mechanisms.

For a complete list of the projects selected, go HERE.

The move is positive step and technologies to trap carbon emissions from coal-fired power plants and store them underground face no “insurmountable” barriers to widespread adoption. The new report, however, concludes that the lack of climate legislation is a big stumbling block.

A multi-agency task force — led by the Energy Department and EPA — delivered recommendations on carbon capture and storage to President Obama on Thursday. The group aims to knock down barriers to widespread deployment within 10 years.

“While there are no insurmountable technological, legal, institutional, regulatory or other barriers that prevent CCS from playing a role in reducing [greenhouse gas] emissions, early CCS projects face economic challenges related to climate policy uncertainty, first-of-a-kind technology risks, and the current high cost of CCS relative to other technologies,” the report states.

It says that Washington’s inability to approve legislation that mandates emissions limits is slowing progress. Most observers believe climate legislation appears dead for the year — and possibly much longer — on Capitol Hill.

“The lack of comprehensive climate change legislation is the key barrier to CCS deployment. Without a carbon price and appropriate financial incentives for new technologies, there is no stable framework for investment in low-carbon technologies such as CCS,” the report states.

“Significant Federal incentives for early deployment of CCS are in place, including RD&D efforts to push CCS technology development, and market-pull mechanisms such as tax credits and loan guarantees. However, many of these projects are being planned by the private sector in anticipation of requirements to reduce GHG emissions, and the foremost economic challenge to these projects is ongoing policy uncertainty regarding the value of GHG emissions reductions,” it adds.