The Utica is starting to step out of the shadow of the Marcellus as technology continues to improve EUR, wells in the play exceed gas production expectations and operators commit increased budgets to the area.

The Utica Shale is a black, calcareous, organic-rich shale of Middle Ordovician age that lies in portions of Ohio, Pennsylvania, West Virginia, New York, Quebec and other parts of eastern North America. The Utica Shale is located beneath the Marcellus Shale, and both are part of the Appalachian Basin, which is the longest-producing petroleum province in the U.S., according to a 2012 U.S. Geological Survey report. The report also said the Utica Shale contains 1.1 Tcm (38 Tcf) of undiscovered, technically recoverable natural gas and has an average of 940 MMbbl of unconventional oil resources and an average of 208 MMbbl of unconventional NGL.

Moreover, gas production for the Marcellus and Utica Shale is expected to grow to 963 MMcm/d (34 Bcf/d) by 2035, compared to 708 MMcm/d (25 Bcf/d) projected in first-quarter 2014, according to ICF International’s second-quarter 2014 Detailed Production Report. “Utica wells are ‘more gassy’ than initially expected; therefore, gas production growth from the Utica wells is expected to be much greater,” the report said.

In addition, improvements in drilling and hydraulic fracturing technology continue to increase EUR per well. “Recent well statistics reported by producers suggest that newer wells have longer horizontal laterals and more fracture stages,” the report stated. Furthermore, “gas EUR in the Utica is projected to average 93 MMcm [3.3 Bcf] per well compared to 70.8 MMcm [2.5 Bcf] per well in the last quarter report,” the ICF report said.

The Utica had a slower start than the Eagle Ford and Marcellus shales in gaining industry momentum, partly due to a slowing, grinding economic recovery after the Great Recession. Comparisons with the two plays are only natural: the Utica is similar to the Eagle Ford in having a condensate/wet gas window, and it is in the same neck of the woods as the Marcellus.

The play seems to have kicked into second gear, however, when operators started expanding into other counties in 2013 that previously had not been considered the “core,” although they were in the fairway.

For example, operators increased well completions in 2013 vs. 2012 in Belmont, Guernsey, Mahoning, Trumbull and Washington counties in Ohio. These counties continue to attract operators such as PDC Energy Inc., Rex Energy Corp. and Hess Corp., which all announced an increase in 2014 capital allocation for the Utica.

Meanwhile, the majority of Ohio’s core counties—Carroll, Harrison, Monroe and Noble—experienced a decrease in wells coming on production in 2013 vs. 2012. Despite the year-over-year decrease in tie-ins, most of the operators that drill in these counties also have announced increases to their 2014 Utica budgets.

Overall, the state of Ohio has reported about 1,230 horizontal permits issued since the play’s inception, beginning in 2010. The state’s fourth-quarter 2013 report shows 397 wells within the play, with 352 reporting associated production results, as the remaining wells are waiting on infrastructure tie-in.

Utica Shale moves south

The Utica Shale play, long concentrated in Ohio, could be most prolific in West Virginia, according to a report from Topeka Capital Markets. The report, which culled first-quarter production data from the Ohio Department of Natural Resources (ODNR), said the play in Ohio was moving south and east toward the Mountain State, where the greatest upside could be in the gas window of the play.

“Based on the data, the most prolific portions of the Utica Shale continue to be in the gassier areas closer to the West Virginia and Pennsylvania borders,” according to the report. Specifically, the core of the dry gas Utica appears to be in Monroe County in Ohio and in Wetzel, Marshall and Tyler counties in West Virginia, according to Topeka. This means West Virginia wells could see IP rates of 849.5 Mcm/d (30 MMcf/d) to 1.4 MMcm/d (50 MMcf/d) and EURs of 424.8 MMcm to 708 MMcm (15 Bcf to 25 Bcf) and higher, according to Topeka.

Citing ODNR data, Topeka found that total first-quarter 2014 production volumes were up 52.7% over the previous quarter, with the bulk of production coming from the Utica and Point Pleasant zones. The best Utica well belonged to Magnum Hunter and produced 625.8 Mcm/d (22.1 MMcf/d) over an eight-day period. This was the same well that Magnum Hunter had previously said produced about 424.8 Mcm/d (15 MMcf/d) over 45 days.

Total first-quarter production in Ohio was 2.2 Bcme (79 Bcfe).

Tackling optimum development

The Utica is the oldest active major shale play in North America. Eastern Ohio was once a shallow, warm-water shelf environment with early marine life forms that generated all T-I and T-II kerogens, which are the best organic materials and make up the Utica-Point Pleasant shales, said Stuart Maier, vice president of geosciences at Gulfport Energy Corp.

Speaking at Hart Energy’s DUG East Conference June 4, Maier described the depositional environment for the shale. “It was isolated, pretty much closed in, oxygen-starved and not a lot of circulation. [Being oxygen-starved] is really key to the preservation of organic matter for subsequent burial and thermal maturity.”

Gulfport and other operators are using science to unravel the optimum development strategy for this play. They are working hard to answer the biggest questions in optimizing development in the Utica-Point Pleasant shales: frack design; well spacing, lateral length and lateral orientation; and production rates.

“These are all dependent variables. I’ll emphasize that you can’t look at one variable without looking at the others. These are all interrelated. The result of that is this is a very complex problem. You have lots of data that go across disciplines,” he explained. “All the working disciplines—engineers, geologists and petrophysicists—have to work together to answer these questions.”

The key factors for the Utica-Point Pleasant shales are the shallow, warm waters and multiple sediment sources that were oxygen-deprived. For the multiple sediment sources, there were clastics coming in, carbonate debris coming in and the deposition of organic matter, Maier said.

“Couple that with rising and falling sea levels, and you’ve got interbedded sand and shale sequences both macroscopically and microscopically,” he added.

In describing a photograph of cores, he pointed out that macroscopically the cores are extremely stratified with respect to the major rocks. Even on a microscopic level the cores are stratified, with fossil debris sitting on top of detritus that is on top of carbonate fossils.

In looking at the mineralogy of one of the shales, there are carbonate grains, some fossil debris, quartz grains and dark areas that are basically organic matter with a little bit of clay. He emphasized that there is a tremendous amount of organic matter. The nature of these organic particles is important on a micron scale.

“The pore network for the Point Pleasant is primarily in the kerogen particles, which create the network,” Maier said. “The spaces are about two microns across. Looking at various sizes of pore throats compared to the approximate size of the largest molecule of oil shows plenty of room in the pore spaces.

“What the organic pore network looks like is a very small, delicate selection of pore throats that form the network,” he continued. “These are very well-connected. The network does have high tortuosity and very restricted flow, which are challenges.

“Gulfport entered the play in late 2010 and on a leap of faith stepped into it. So far it has paid off. Currently, we have 179,000 net acres in the play and seven active drilling rigs,” Maier said.

Although the company has some of the highest IP rates in the play, it has a long way to go to determine the optimum frack design, lateral length and spacing.

“What we’re doing to address this is on our Darla pad, where we’ve constructed a geomodel. We are going to do microseismic when we frack the wells and run chemical tracers. We’ve run optic fiber along the outside of the casing on three of the wells to monitor fluid flow. We are also going to run some production logs to see how the various zones contribute,” Maier explained. “The three Darla wells are built in a fan pattern to really monitor the effect of well spacing along those laterals.”

The well pad will be used to identify where each cluster is located in the Point Pleasant, monitor the frack job with fiber optics and see how many clusters per stage are effective. One of the variables the company looks at is the kind of rock where the frack is initiated.

“We will monitor the frack jobs of one of these wells to see which perf clusters take fluid. That is one of the big questions—what is your perf cluster efficiency? How many perf clusters and stages are you effectively treating?” he asked. “We should be able to find that out.”

In the Utica, the company expects to drill about 80 wells in 2014, which is about a 25% increase over 2013. Gulfport is still very early in the play and has a lot of work left to do and a lot of science yet to gather.

Water treatment system enables flowback reuse

Reusing produced and flowback water in hydraulic fracturing operations is transforming the industry’s biggest waste product into a resource while also reducing the environmental footprint.

By Morgan McCutchan, Baker Hughes

It has been more than a decade since the oil and gas industry cracked the code that launched the North American shale boom. Along the way, breakthrough technologies have helped operators overcome a multitude of barriers to produce fields more efficiently, economically and safely while reducing the environmental footprint.

One of the biggest challenges confronting producers centers on what is arguably shale production’s greatest enabler: water. The tremendous amount of water needed to fracture a well and the subsequent issues and costs to transport and dispose of it have prompted companies to consider solutions for reusing, recycling and reclaiming this precious resource in ways that make both economic and environmental sense. Reusing produced and flowback water in hydraulic fracturing operations is proving to be a win-win proposition, transforming the industry’s biggest waste product into a resource, with the added benefit of reducing the environmental footprint.

Baker Hughes’ water management service uses environmentally preferred chemistry to effectively treat and clean produced and flowback water for reuse. The process has been essential to use in the prolific shale plays because the logistics of trucking and disposing of wastewater have become increasingly more difficult. The system has proved beneficial in helping the operators reduce their demand for freshwater and has improved field economics by significantly lowering trucking and disposal costs.

Situated in the expansive Appalachian Basin along the eastern U.S., the Utica Shale gas play spans through nine states and Canada; however, production is expected to be most prolific in Ohio, West Virginia, Pennsylvania and New York. The Utica play accounts for a significant share of the basin’s oil production, which between 2012 and 2013 increased nearly 95%, according to a June 2014 Southeastern Ohio Oil & Gas Association Gas Committee Report. Extracting gas from the Utica requires large amounts of freshwater from lakes, rivers and streams that is either stored in nearby impoundments or in some cases trucked from a water source, posing safety and cost issues.

A typical Utica Shale well fracturing operation can use on average 19 MMl (5 MMgal) of water, and roughly 15% to 20% of that—between 2.8 MMl and 3.8 MMl (750,000 gal and 1 MMgal)—flows back to the surface. Managing this flowback water is challenging for a variety of reasons, including disposal and how to treat contaminants.

When it comes to the Utica Shale play, the majority of the wells being drilled and completed are in Ohio. Ohio has numerous disposal wells, but they are not always close to a disposal site, and they have limitations on the amount of fluid that can be transported to them through the lines.

Disposal, trucking concerns

Due to limitations, the wastewater often is trucked by third-party transport firms to saltwater disposal wells (SWDs) at a cost of $8 to $12 per barrel. Trucking poses increased risk of accidents, spills and road damage. In addition, SWDs often face permitting delays, which can postpone drilling new wells that would increase capacity in the area.

Onsite treatment of produced and flowback water in Ohio is stringently regulated. Under requirements of the Ohio Department of Natural Resources, onsite water treatment of produced and flowback water must be carried out in above-ground storage tanks to prevent accidental fluid release.

These challenges have prompted operators to examine various water treatment methods for poor-quality flowback and produced water that is being moved by truck to above-ground storage tanks. Similar to produced water in other shales like the Marcellus, the water often contains significant bacteria, dissolved iron, hydrogen sulfide (H2S) and iron sulfide (FeS) and also emits an unpleasant odor. All the contaminants limit the water’s reuse, and the H2S presents safety concerns in fluid-handling and hydraulic fracturing operations as well as potential corrosion during production. High levels of iron can break down the friction reducers required in slickwater fracturing operations, and high sulfate-reducing and acid-producing bacteria can contaminate the wellbore.

Typically, several chemical applications are considered and can include liquid biocides that address only some of the contaminants and surfactants for odor control. A common solution is a comprehensive system that uses chlorine dioxide (ClO2), which is a fast-acting oxidizer used to treat about 30% of U.S. drinking water. The treatment can be generated on site via mobile or permanently mounted generators to treat produced and flowback water in above-ground tanks.

Baker Hughes’ H2prO HD water treatment system neutralizes microorganisms, H2S, FeS, phenols, mercaptans and polymers in the surface water, allowing the water to be reused for downhole operations with no threat of corrosion and equipment plugging. The treated water poses no reservoir damage or HSE issues, including offensive odors and dangerous fumes, which occur with the presence of H2S.

The oxidizer system, which has been approved by the U.S. Environmental Protection Agency, uses three common liquid precursors—sodium hypochlorite, hydrochloric acid and sodium chlorite. The automated system is designed with inline monitoring and built-in safety features that ensure the ClO2 is activated in water only while the vacuum-based generator is running, even if power is lost. By using no more than 3,000 ppm, the system keeps power costs low, further reducing the environmental footprint. A mobile unit can be assembled in about an hour and can treat up to 200,000 bbl/d of water.

Reducing freshwater demand

A key objective for operators in deploying the mobile ClO2 oxidizer system is to treat produced and flowback water in tanks before it’s blended with freshwater for use in hydraulic fracturing operations. For example, a hybrid strategy for one operator was implemented with water in the first impoundment treated on-the-fly as it was being transferred. Water from the other two impoundments received batch treatments in place, which required the impoundments to be thoroughly mixed before, during and after the treatment to reduce the chance of hot spots occurring due to excessive chemical residue. Mixing also ensures that all contaminants are effectively oxidized.

A thorough water analysis was performed on all the source water impoundments prior to treatment to determine the ionic and bacterial composition of the water and the amount of ClO2 that would be needed for treatment. The source water also was periodically tested during the treatment process, and finished product samples were taken to measure water quality and check for any ClO2 residue.

About 300,000 bbl of water were treated from the three impoundments. The treatment resulted in an eight-bottle log reduction in bacteria and complete oxidization of the FeS. The process significantly improved the water clarity and eliminated the odor, resulting in a greater percentage of the produced water becoming eligible for reuse. By removing the contaminants from the produced and flowback water, the operator was able to achieve the same hydraulic fracturing formulation typically required for freshwater.

The use of the mobile ClO2 treatment service delivered multiple benefits to the operator, significantly reducing the costs and risks associated with water disposal and transportation, and it preserved millions of gallons of water already in the impoundments, thus eliminating the need for additional freshwater sourcing.

Ongoing success in the shale plays is dependent on optimizing field and wellbore economics while conducting operations in ways that reduce the environmental footprint. Development of technologies that enable prudent use and reuse of water signifies an important step-change in the industry’s ability to confront and overcome extraordinary challenges to the safe and efficient production of hydrocarbons in these important frontiers.