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Stimulating Future

Positive results are emerging from fracturing field laboratories.

 

 

John Duda and Cassie Shaner, NETL
Mon, 01/06/2020 - 11:00 AM

 

 

Hydraulic fracturing has come a long way as a means of stimulating oil and natural gas reservoirs since its first experimental use in the 1940s, thanks in large part to revolutionary technological advances led by the U.S. Department of Energy (DOE) that helped usher in the modern shale gas boom.

Natural gas derived from shale formations accounts for the bulk of U.S. natural gas production, rising from 1.3 Tcf in 2007—the first year for shale-specific record-keeping by the U.S. Energy Information Administration (EIA)—to 18.6 Tcf in 2017. Production from shale formations and tight oil plays is expected to rise to roughly 33.3 Tcf by 2050, accounting for more than 75% of the natural gas produced nationwide.

Because of plentiful domestic shale gas produced using hydraulic fracturing techniques, the U.S. led the world in natural gas production in 2018, notching record growth and setting a new annual production benchmark.

The DOE’s National Energy Technology Laboratory (NETL), the nation’s only federal research laboratory dedicated to fossil fuels, has a rich history of innovation when it comes to hydraulic fracturing. In the 1970s, fears that U.S. natural gas resources were dwindling prompted federally sponsored research focused on unconventional natural gas reservoirs, such as gas shales, tight sandstones and coal seams that were previously uneconomical to develop.

As part of the Eastern Gas Shales Research Program, the NETL helped to advance large-volume hydraulic fracturing technology. In 1975 a DOE industry joint venture drilled the first directional wells in the Appalachian Basin to tap shale gas and, shortly thereafter, completed the first horizontal shale well that used seven individual hydraulically fractured intervals. The DOE integrated basic core and geologic data from 35 research wells to prepare the first publicly available estimates of technically recoverable gas for gas shales in West Virginia, Ohio and Kentucky.

Today the NETL is building upon that legacy via collaborative investigation of ways to increase resource recovery efficiency. Field laboratories within the Permian, Appalachian, Williston and Eagle Ford basins are shedding light on subsurface questions associated with unconventional reservoirs and providing meaningful insights to help meet the energy needs of future generations.


Marcellus Shale Energy and Environmental Laboratory

Established in 2014, the Marcellus Shale Energy and Environmental Laboratory (MSEEL) was among the DOE’s first field laboratories. The $25 million project was created to develop and validate new knowledge and technology to improve recovery efficiency and minimize the environmental implications of unconventional resource development.

The NETL manages the project and provides technical oversight on behalf of the Office of Fossil Energy. The MSEEL, which spans two Northeast Natural Energy (NNE) production sites outside Morgantown, W.Va., is run by nearby West Virginia University (WVU) and involves a consortium of other universities and national laboratories.

The initial site at the Morgantown Industrial Park (MIP) featured two wells, which provided a well-documented baseline of production and environmental characterization data. A dedicated scientific observation well was drilled to collect detailed subsurface data, including log data. Operators collected 111 ft of 4-in. whole round core, believed to be the first core extracted through the entirety of the Marcellus Formation.

In addition, 147 sidewall core samples were taken, which researchers used to conduct geochemical, microbiological and geomechanical investigations. The observation well also was instrumented with a downhole seismic array to monitor stimulation events in two new production wells (identified as MIP 3H and 5H) that NNE began drilling in late June 2015. The MIP 3H lateral was logged and instrumented with permanent fiber-optic sensors. 

NNE recently established a second MSEEL location, known as the Boggess site, featuring six horizontal production wells—all logged with the latest LWD tools and including one fully instrumented with permanent fiber-optic wiring and sensors to provide near-real-time information during fracturing and production.

The initial project plan called for sample and data collection as well as testing and demonstration of advanced technologies. But the project’s phased approach and access to multiple Marcellus wells provided the flexibility to expand the project’s scope by identifying and incorporating innovative new tools and techniques focused on increasing recovery efficiency.

Lessons learned from the MSEEL within the past five years have increased reserves at the MIP well site by 20% and contributed to best practices that NNE incorporated into its other operations. Other operators in the Appalachian Basin are adopting state-of-the-art techniques and technologies that have been demonstrated and confirmed as part of this project. For example, the use of 100 mesh sand proppant and synthetic drilling mud has become a common practice throughout the basin. 

MSEEL's Boggess site The MSEEL’s Boggess site, established in 2018, features six horizontal production wells, including one fully instrumented with permanent fiber-optic wiring and sensors to provide near-real-time information during hydraulic fracturing and production. (Source: NETL)

Completion design
The MSEEL team developed an engineered design methodology for well completion that enhances effectiveness by increasing the percentage of perforation clusters along the lateral contributing to production. The methodology—based on core sampling, fiber-optic sensing and LWD data—minimizes the effect of lateral heterogeneity on fracture stimulation. These measurements are used to predict breakdown pressure, which was then used to place stages and perforation clusters in rock with similar mechanical properties, thereby improving the probability of stimulating all clusters within a given treatment stage.

Perforation impacts on productivity
Research at the MSEEL site indicated that fewer perforations are needed per stage than had been previously used. By using fewer and smaller holes, NNE was able to increase the rate of injection, which facilitated more efficient fracturing by delivering sand more effectively into the induced cracks. Coupled with this, NNE learned that upgrading the casing string and frac stack to withstand higher pressures more effectively ensured that every perforation cluster was stimulated effectively.

Vehicle impacts
NNE learned that silica exposure can be controlled by using a cost-effective box-type sand delivery system versus a standard truck-and-trailer system. This is another technique widely used throughout the basin. Researchers also learned that a natural gas hybrid rig does not reduce emissions as much as previously believed, nor does it provide significant cost savings.

Drilling mud
The MSEEL provided confirmation that synthetic drilling mud produces cuttings that are more environmentally friendly to dispose of than traditional cuttings and improved drilling performance. This type of mud is commonly used by NNE and other operators in the basin. 

Recovery efficiency
Fiber optics and production logging proved that increased 100 mesh sand concentrations do not degrade reservoir performance when compared to larger sand proppant. It improves both fracture stimulation and decreases costs as more sand can be shipped per container volume. NNE uses a much higher percentage of 100 mesh sand as part of its standard frac design.

Fracturing and efficiency
WVU developed a software system called FIBPRO to analyze fiber-optic distributed acoustic sensing, distributed temperature sensing and microseismic data collected during hydraulic fracturing of the MIP 3H well. Analyses using FIBPRO showed that the distribution of deformation and crossflow between stages demonstrated differences in completion efficiency among stages and clusters. These differences affected production efficiency and resulted in a better understanding of the geological/geomechanical controls on completion and, ultimately, on well production.

Fracture geometry
WVU developed an integrated geomechanical and discrete natural fracture model to investigate the complexity of hydraulic fracture geometry. History matching and production response, as measured by fiber-optic data and production logging, confirmed the reservoir simulation and importance of engineered hydraulic fractures. Well spacing sensitivity research was done to identify the optimal distance between laterals to maximize recovery and the number of wells per section.

Numerical modeling was conducted to simulate stimulation Stages 1 through 3 of the MIP 3H well, using measured injection data. Comparison of measured data and slurry volumes, slurry rates and proppant mass estimated by the model showed strong correlation with stimulation efficiency. This modeling will continue for other stages, incorporating microseismic and production spinner test data, to better model fracture geometries.

Geochemistry
New microorganisms have been recognized in the deep biosphere represented by the Marcellus Shale. Subsurface microbial communities affect energy production, reservoir properties and wellbore integrity through processes such as biomineralization (scaling), acid formation (corrosion), biofilm formation (biofouling) and metal mobility. Understanding these organisms is important to reduce downhole well damage and scaling as well as precipitation of radium in surface facilities. To better analyze the biogeochemical characteristics of Marcellus Shale and investigate geological controls on microbial distribution, diversity and function, researchers developed new methods to maximize recovery and reproducibility of lipid biomarkers—efforts that are enhancing researchers’ understanding of subsurface biogeochemistry and the effect on long-term production. Researchers at the NETL have investigated water/rock interactions and the effects of barite precipitation on production efficiency.

Water impacts
Continuous monitoring of flowback and produced waters for nearly a year showed that total dissolved solids leveled off, with little change in ionic composition. Radionuclides in the drill cuttings were consistently below West Virginia Department of Environmental Protection levels for landfill disposal and well below U.S. Department of Transportation levels for classification as low-level radioactive waste. Findings from the analysis of the MSEEL drill cuttings aided West Virginia legislators in establishing new statewide waste disposal criteria based on the U.S. EPA’s toxicity characteristic leaching procedure, which has not been exceeded for either organic or inorganic constituents in the MSEEL drill cuttings.

Emissions
Direct-reading aerosol sampling was conducted throughout all stages of well development at the MIP site except pad preparation. Sampling locations included the drill pad, 1-km and 2-km distances. EPA-regulated PM2.5 (particles less than 2.5 micrometers in diameter, capable of reaching human lung airspaces) emissions were not detectable from background at 1-km downwind during the highest emissions periods (hydraulic fracturing) on the well pad. Monitoring during drilling and completion operations indicated that a significant portion of air emissions was from truck traffic and other mobile sources, not from emissions due to pad operations. Emissions audits conducted at the MIP site using stationary and mobile systems indicated that the primary contributor to methane emissions on site was a produced water tank.

Next steps
Continued work at the MSEEL’s two sites builds upon the revelations and achievements of the project’s earlier work, with a focus on economics.

The initial efforts at the MSEEL advanced hydraulic fracturing stimulation techniques that the NETL researchers pioneered years ago. The current R&D is geared toward cost-effectively improving gas recovery from horizontal drilling and hydraulic fracturing in the region. A key objective of the latest field test is to demonstrate optimal completion strategies that can be applied to other areas of the Marcellus Shale play to improve overall resource recovery efficiency. 

For example, modeling from nanopore to reservoir-scale by WVU at the original MSEEL site advanced the understanding of the frac response and affected rock volume and the approaches and capabilities to handle and process large datasets from a single well. It also helped optimize spacing between laterals, stage length and cluster design. Technologies advanced at the MSEEL enabled NNE to design better wells. In addition, several technologies have been developed since the MSEEL began that facilitate acquisition of the same type of information much more cost-effectively when coupled with advanced modeling. That is the critical focus of the MSEEL project’s next phase. 

The NETL and its project partners also are building better models that offer deeper insights. A team of NETL researchers is conducting computed tomography imaging and logging 139 ft of 4-in. whole round core and 50 sidewall cores retrieved from the Boggess site’s 17H pilot well. The data will be used to develop a high-resolution geomechanical model of the Marcellus that could yield the capability to improve production efficiency and environmental performance throughout the Marcellus Shale region.

Work at MSEEL’s Boggess site near Morgantown, W.Va., is focused on learning from prior research and integrating the latest innovations to improve resource recovery and project economics while reducing environmental impacts. (Source: NETL) Work at MSEEL’s Boggess site near Morgantown, W.Va., is focused on learning from prior research and integrating the latest innovations to improve resource recovery and project economics while reducing environmental impacts. (Source: NETL)

The MSEEL project demonstrated a model government-private sector partnership, with WVU at the helm. The project has shown that safe and efficient operations can be conducted with no long-term environmental consequences. Because of NNE’s successful demonstration of technologies and techniques, these practices have been adopted by other operators in the basin.


Hydraulic Fracturing Test Sites 1 and 2

The NETL teamed up with the Gas Technology Institute (GTI), of Des Plaines, Ill., in 2014 to launch a comprehensive diagnostics and testing program focused on reducing  and minimizing environmental impacts, demonstrating safe and reliable operations, and improving the efficiency of hydraulic fracturing. The research collaboration is focused on two hydraulic fracturing test sites (HFTS 1 and HFTS 2) about 140 miles apart in the Permian Basin of West Texas and New Mexico. The program emulates field experiments that the DOE/NETL and the Gas Research Institute—one of two entities that combined to form GTI—performed in vertical wells in the 1990s.

Technology has evolved to favor longer horizontal shale wells with multiple hydraulic fracturing stages, introducing a new set of challenges and unanswered questions. For instance, the optimal number of fracturing stages during multistage fracture stimulation in horizontal wells is unknown. Multistage fracturing in horizontal wells raises costs, yet the increase in fracturing stages does not always correlate to a rise in production.

Applying a uniform fracture stimulation design to all stages does not account for geological variations along the wellbore, and efficiency is not maximized. Improvements in the design and execution of fracturing processes will reduce the number of infill wells to be drilled, the amount of working fluid used and energy demand for future oil and gas recovery activity.

Optimization of the fracturing process requires an understanding of the cause-and-effect relationship between fracturing parameters and geological properties at a given location along the wellbore. A comprehensive understanding of the quantifiable impacts of a shale’s geomechanical and depositional features is required to design and implement an optimal hydraulic fracturing strategy. Researchers at HFTS 1 and 2 are conducting conclusive tests designed and implemented using advanced technologies to characterize, evaluate and improve the effectiveness of individual hydraulic fracture stages.

Laredo Petroleum provided a field site in Reagan County, Texas, for the $32 million HFTS 1 project. The site features 11 horizontal wells in the Wolfcamp Formation of the Permian-Midland Basin. Prior to and after hydraulic fracturing operations, researchers with GTI conducted seismic surveys to produce images of the subsurface geology, collected water and air samples and undertook microseismic monitoring to detect very small-scale seismic events that occurred as a result of fracturing.

In addition, researchers used tracers to study the distribution of proppant. While all planned Phase 1 fieldwork for HFTS 1 has been completed, data analysis and integration are ongoing. Additionally, pressure, temperature and production data from the test wells continue to be collected for future analyses. The information gathered through the project is the most meaningful dataset to date for unconventional oil and gas production, providing information essential to understanding induced fractures, validating and developing models, and assessing how predictive analytics can improve the process.

The $27 million HFTS 2 project was initiated in 2018. Anadarko Petroleum Corp. and Shell Exploration and Production Co. agreed to host a new field site in Loving County, Texas, within the Permian-Delaware Basin, that features different depths, pressures and permeability than HFTS 1.

As of mid-2019, all wells on the eight-well pad were drilled, and two were fitted with fiber-optic sensors. An additional vertical pilot well was drilled, cored and instrumented with permanent fiber-optic cable and pressure gauges. Fracturing operations were underway, with associated analyses pending.

While the goal of HFTS 1 was to understand and define the relationships of shale geology and fracture dynamics, HFTS 2 is focused on optimizing hydraulic fracturing and well spacing.

The NETL-funded HFTS 1 and HFTS 2 are located about 140 miles apart in the Permian Basin of West Texas and New Mexico. (Source: NETL) The NETL-funded HFTS 1 and HFTS 2 are located about 140 miles apart in the Permian Basin of West Texas and New Mexico. (Source: NETL)

Impacts of fracturing operations
More than 400 fracture stages were completed in the 11 wells at HFTS 1. The core description was completed by multiple teams, and results have been incorporated into a final core description report. Two main sets of natural opening-mode fractures filled with calcite cement were identified, trending broadly northeast to southeast and west-northwest to east-southeast. Eleven faults were identified, all within the Upper Wolfcamp Formation. More than 700 fractures (natural and induced) were identified in the core.

Fracture insights
Results indicate that fracture quantity and complexity are far beyond what current simulators/models can predict. Stimulation creates multiple far-field fractures (100 ft away), which are not uniform in distribution with fracture clusters and voids. Variable-rate fracturing provides an uplift to production by improving perforation efficiency without adding extra costs. 

Air and water impacts
Air and water samples were collected prior to, during and after hydraulic fracturing operations. Air quality data and analysis indicated a little-to-no increase in regulated air quality compounds during fracturing and production operations at the test site, though there is potential for elevated emissions during flowback when open systems are used. In addition, there was no evidence of natural gas or produced water migration to the groundwater aquifer. Research to date shows that hydraulic fractures do not grow into freshwater zones.

Proppant impacts
Vertical proppant distribution measured in the core is only a fraction (5%) of the measured microseismic geometry. Multiple proppant packs were found. Others were likely washed out during coring, indicating inefficient proppant placement. Propped fracture dimensions are very different from hydraulic fracturing dimensions.

Geological distinctions
A slant core well was successfully drilled through the stimulated rock volume between two horizontal wells, recovering 595 ft of core spanning the upper and middle portions of the Wolfcamp Formation. This was the first such core ever taken as part of a publicly funded research project. Analysis indicated that the Upper and Middle Wolfcamp formations vary considerably. The Upper Wolfcamp features many times more hydraulic and natural fractures, leading to very different fracture half-lengths and spacing implications.

Fracturing & production

Variable-rate fracturing provides an uplift to production by improving perforation efficiency without adding extra costs.

A proppant pack is shown in a hydraulic fracture of an Upper Wolfcamp Formation core. (Source: NETL) A proppant pack is shown in a hydraulic fracture of an Upper Wolfcamp Formation core. (Source: NETL) Core samples from HFTS 1 show unique distinctions between natural fractures and those produced via hydraulic fracturing. (Source: NETL) Core samples from HFTS 1 show unique distinctions between natural fractures and those produced via hydraulic fracturing. (Source: NETL)

Next steps
The HFTS projects are capturing fundamental hydraulic fracturing insights that will influence the exploration and development of different shale formations for many years. Researchers are continuing to analyze and integrate various datasets to gain an enhanced understanding of the fracturing process.

As the primary research work at HFTS 2 proceeds, HFTS 1 has moved on to Phase 2, which focuses on EOR methods. The EOR field pilot involves a new set of wells about 1 mile northwest of the existing Phase 1 experimental wells, with an updated completion design that reflects lessons learned in Phase 1. The site includes a central injector/producer to test cyclic gas injection, offset by horizontal and vertical wells equipped with downhole pressure and temperature gauges used to monitor gas movement during injection in the reservoir.

Both HFTS projects offer an immediate impact to the industry because each effort involves a joint industry partnership (JIP) composed of more than a dozen oil and gas companies and operators (including six involved in both projects) that provide technical support and share costs. The JIPs will accelerate the adoption of technology innovations and best practices being developed.


Bakken/Eagle Ford Laboratories

As hydraulic fracturing methods continue to evolve and allow improvements in stimulated volume, a large percentage of recoverable oil remains in the ground after IP. The NETL partnered with the University of North Dakota’s Energy & Environmental Research Center (UND-EERC) to initiate an EOR-focused field laboratory
project at the Stomping Horse complex within the Williston Basin’s Bakken Shale play in western North Dakota. The collaboration began in September 2017.

Preliminary laboratory investigations suggest that ethane and mixtures of methane and ethane may be used to mobilize oil from the Bakken reservoir and be viable injectate for tertiary EOR operations. The EERC engaged Liberty Resources and the North Dakota Industrial Commission, through the Bakken Production Optimization Program, to design and conduct an EOR pilot test using rich gas. The primary goal of the project, along with the newer Eagle Ford Shale Laboratory launched in 2018, is to better characterize existing fracture networks, stimulated reservoir volume and fluid flow dynamics to improve EOR opportunities.

Baseline reservoir characterization data collection has been completed for all wells within the Leon-Gohrick drill spacing units in the Stomping Horse complex. Parameters measured included analysis of produced oil, water and gas as well as bottomhole pressure and temperature for wells permitted for injection and offset wells.

Pressure
Minimum miscibility pressure (MMP) studies have been conducted to determine the MMP of rich gas components and different rich gas mixtures in oil from the Stomping Horse complex. MMP data for methane, ethane, propane and different relevant mixtures have shown that “richer” gas mixtures will result in lower MMP values (e.g., methane MMP > ethane MMP > propane MMP).

Types of injection gas
Rock extraction studies of the rich gas components on Bakken shale and nonshale samples show that, when it comes to mobilizing hydrocarbons from Bakken rocks, methane is the least effective, propane is the most effective and ethane has an intermediate effect. The rock extraction studies also show that propane is effective at all pressures; ethane is effective at higher pressures and methane is the least effective at any pressure.

Modeling studies
Modeling-based studies of the potential effects of rich gas EOR operations on the surface infrastructure of the Stomping Horse complex predict that the process will not adversely affect surface facility operations. Reservoir modeling of selected injection/production scenarios predicts that incremental oil recovery may exceed 25%.

Injection testing
Small-scale injectivity tests were conducted in two wells in the Stomping Horse complex during summer 2018. A total of 24.6 MMscf of rich gas was injected during three tests. The maximum injection rate achieved was 1.14 MMscf/d. Downhole pressure and temperature data were collected before, during and after the injection tests from six wells in the drill spacing unit, including the injection wells and the immediately adjacent offset wells. Data obtained from the small-scale injection tests were used to refine the design of the subsequent larger pilot tests.

Fast flow pathways
A tracer was introduced to the injection well during large-scale pilot tests. Multiple sampling events from multiple wells were conducted in the Stomping Horse complex as a means of identifying fast flow pathways between the injector and various offset wells. The maximum injection rate for the large-scale test is 2 MMscf/d. In general, each cycle injection is conducted until one of three criteria is achieved: total injection of 60 MMscf, 30 days of injection or clear evidence of substantial breakthrough at an offset well.

Next steps
Management of rich gas production from the Bakken is a high priority for government and industry stakeholders in North Dakota, due to economic challenges associated with expanding gas-gathering infrastructure in the relatively geographically isolated location. The NETL’s efforts with UND-EERC aim to demonstrate the viability of using rich gas for EOR in the Bakken, which would result in reduced flaring and improve oil recovery.

A pilot injection test and associated monitoring activities are ongoing, and shale permeability and shale sorption studies, using a flow-through testing approach, continue. The effects of rich gas exposure on the properties of Bakken shale and nonshale tight rocks, including clays and mineralogy, wettability and relative permeability, are being examined using a variety of laboratory techniques, such as nuclear magnetic resonance and field emission scanning electron microscopy. The potential for preferential sorption of different rich gas components in Bakken rocks also is being examined using flow-through experiments under reservoir pressure and temperature conditions.

Similarly, the emerging Eagle Ford Shale Laboratory seeks to improve the efficiency of oil and gas recovery from hydraulically fractured horizontal wells on INPEX Eagle Ford LLC’s shale properties in LaSalle County, Texas. The project teams Texas A&M University with Lawrence Berkeley National Laboratory and Stanford University. Funding is provided by the NETL, with a match from INPEX Eagle Ford LLC and contributions by other operators and service companies via a JIP agreement.

Field-based research within the Eagle Ford Shale formation began in April 2018 and is ongoing. Using newly developed and comprehensive monitoring solutions, the team will deliver unprecedented and comprehensive high-quality field data to improve scientific knowledge of the hydraulic fracturing process, refracturing and subsequent huff-and-puff gas injection. This knowledge will facilitate optimized production from a reduced number of new wells, with less material and energy use.


Key Takeaways and Future Steps

The research conducted by the NETL’s field laboratories has helped to redefine the public’s perception of unconventional oil and natural gas exploration by delivering an unbiased view of the environmental impacts of the drilling and stimulation processes, which research has demonstrated to be relatively benign. Simultaneously, the NETL is identifying new possibilities for hydraulic fracturing technologies that offer the potential to optimize operations and boost resource recovery beyond current levels.

For instance, several technologies have been developed since the MSEEL began that, when coupled with advanced modeling, could allow the acquisition of the same type of information in a much more cost-effective way. If the project’s current efforts prove that these innovations work and lead to improved production results, the project will lead to more efficient and effective resource recovery within the Marcellus Shale region and possibly throughout other shale plays nationwide—particularly when combined with insights from HFTS 1 and 2.

The Phase 2 work at HFTS 1 complements the EOR field research underway at the Bakken laboratory site. Each project ultimately seeks to improve the effectiveness of shale oil production by providing new scientific knowledge related to stimulation and production as well as enhanced recovery via refracturing and EOR.

Research by the NETL and its partners is providing new insights into the fracture stimulation and EOR processes, which will aid in the development of new methodologies and tools to maximize the production of oil from fractured shale. While some research results will apply to specific formations, many realistic and practical learnings will be applicable to other unconventional plays and subsurface applications, such as tight gas sand reservoirs and even saline formations for CO2 storage.

The DOE is using data collected from these demonstration projects and new field laboratory projects awarded in fiscal year 2019 to support artificial intelligence and machine learning. The results of this work will yield fundamental knowledge of shale fracture and matrix properties. Additionally, analytical tools for assessing hydraulic fracture performance and methods of targeting distinct features of the hydraulic fracture system will be developed to improve production efficiency and increase resource recovery.

 

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This Isn't Your Father's Oil and Gas Rig Count

 

Every Friday, the Baker Hughes oil and natural gas rig count gets released. This is vital field information that energy analysts eagerly await. In essence, the count is supposed to convey the current thinking of the U.S. oil and gas industry. As it is supposed to go, higher oil prices mean higher rig counts which mean higher production. And in the opposite direction, lower prices mean less rigs and falling production. While it is true that more rigs usually enter the fields when prices go up, it can take months of higher prices before drillers are confident enough to bring additional rigs into service. And there is also a lag time with dropping prices, not immediately dragging the rig count lower. Many times lower prices just mean removing the less efficient rigs from the field.

There is an evident connection between the U.S. oil-directed rig count and prices (see Figure 1). As measured from -1.0 to +1.0, the Correlation Coefficient for these two variables measures a strong +0.85, with both moving in the same direction up or down. Yet to be sure, incredible efficiency gains in the U.S. shale industry over the past five to seven years have changed things a bit. Burdened with a crushing low price environment from 2014 to 2017, the U.S oil and gas business faced a simple option: either improve operations and significantly cut costs or ready the bankruptcy papers. The innovations of shale companies continue to surpass anything thought possible.

 

 

 

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Most can agree that we cannot really blame analysts for being so wrong about the shale revolution, a deficiency likely to continue on into the coming decade. Going back to 2007, for instance, shale was not even being mentioned as a potential source of major new supply. While probably growing slower in 2020, the industry has transformed global energy markets in ways never thought possible – not even by the oil and gas companies themselves. This helps explain why the IEA forecasts that the U.S. will account for 85% of new global crude output and 35% of new natural gas through 2030. For finances, WTI prices sticking above $65 or $70 would be just the boost the shale industry needs. Ultimately, it will be a burgeoning U.S. export business that will mandate new output. The EIA has domestic gas demand rising 1-2% per year for decades to come, while the country’s oil use will remain flat or even decline slightly

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Port Arthur LNG Progresses with Aramco Deal

 

 

Saudi Aramco’s Aramco Services Co. unit has signed an interim project participation agreement (IPPA) with Sempra LNG for the latter firm’s Port Arthur LNG project under development in Jefferson County, Texas, Sempra Energy reported Monday.

According to Sempra, the IPPA marks another milestone for the companies in conjunction with Port Arthur LNG. Last May, Aramco signed a heads of agreement with Sempra to purchase 5 million tonnes per annum (mtpa) of LNG from Port Arthur LNG and to acquire a 25-percent equity investment in the project.

“Today’s announcement is a reflection of the growing alignment between our companies’ interest in the overall success of the Port Arthur LNG project,” commented Sempra Energy Chairman and CEO Jeffrey W. Martin. “We have a tremendous amount of respect for Saudi Aramco and its leadership team and we are pleased we can support their success in the global natural gas markets.”

Sempra noted that it expects the fully permitted initial phase of Port Arthur LNG to include two liquefaction trains, up to three LNG storage tanks and associated facilities to enable approximately 11 mtpa of LNG exports long-term. The company added that it recently initiated the Federal Energy Regulatory Commission (FERC) pre-filing review process for the agency to consider a potential expansion of the proposed Port Arthur LNG project. The expansion would add two liquefaction trains – bringing the total to four – and give the terminal the capability to export approximately 22 mtpa of LNG, Sempra noted.

“The global demand growth for LNG is expected to continue in the coming years, and we see significant opportunities in this market,” stated Amin H. Nasser, Saudi Aramco’s president and CEO. “This agreement with Sempra Energy is another step forward for Saudi Aramco’s long-term gas strategy, and towards becoming the global leading integrated energy and chemicals company.”

In its written statement, Sempra cautioned that the Port Arthur LNG export project remains subject to final investment decisions by various parties and other conditions. Company spokesperson Paty Ortega Mitchell told Rigzone Tuesday that the IPPA represents another step toward finalizing Sempra’s arrangements with Saudi Aramco for the 5-mtpa offtake deal and 25-percent equity acquisition.

“It outlines key milestones and mechanisms as both parties work toward executing the project agreements and taking final investment decisions,” Mitchell explained. “Both parties are large entities with boards that meet on a predetermined schedule.”

 

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Thank you. Very informative.

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Oh shale deniers will deny these job exists !!!!

Shale haters will say its all  made up by royalty owners and non producers and so on

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Permian Oil and Gas Employs 87,000 People in 2019

 

 

Direct oil and natural gas employment in the Permian basin totaled 87,603 people in 2019, according to a new report from the Texas Independent Producers and Royalty Owners Association (TIPRO).

The report, which outlined that this figure represented an increase of nearly 43,000 jobs since 2009, highlighted that the largest Permian basin counties by oil and natural gas employment in 2019 included Midland (33,328), Ector (14,791), Lea (8,356), Eddy (7,766) and Hockley (2,765).

The largest increase in oil and gas employment between 2009-2019 occurred in Midland County (20,802), followed by Ector (7,693), Eddy (4,985), Lea (2,407) and Hockley (1,513), according to the report.

TIPRO’s report said the upstream sector remained the top employer for oil and gas in the Permian basin last year. Support activities for oil and gas operations supported 54,507 positions, crude petroleum and natural gas extraction supported another 16,572 jobs and drilling oil and gas wells supported 6,554 jobs, according to the report.

Fifty-four percent of Permian basin oil and gas workers in 2019 were between the ages of 25 and 44 and approximately 37 percent were 45 years or older, the report showed. In 2019, Permian companies employed more than 12,560 women and 48 percent of all oil and gas jobs were held by Hispanic or Latino workers, according to the report.

In September last year, TIPRO forecasted that the Permian basin oil and gas industry will support 93,201 jobs in 2020.

The total number of oil and natural gas businesses in the Permian basin exceeded 3,350 in 2019, with the highest number of oil and gas businesses located in Midland County (1,012), TIPRO’s latest report outlined.

Total oil production in the Permian basin exceeded 1.5 billion barrels of oil in 2019 and oil production increased by 1.2 billion barrels in the region between 2009-2019, the report noted.

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The first cargo of ethylene from Enterprise Products Partners L.P. and Navigator Holdings Ltd.’s new marine terminal near Houston has set sail.

Enterprise and Navigator reported Wednesday that the Navigator Europa – carrying 25 million pounds of ethylene for the Japanese trading company Marubeni Corp. – has departed their new export terminal at Morgan’s Point, Texas, along the Houston Ship Channel.

“The opening of the jointly owned ethylene export terminal represents the beginning of an expansion of the export of valuable intermediate petrochemical gas products including ethylene and propylene,” David Butters, executive chairman of Navigator Gas, said in a written statement issued by 50/50 joint venture partner Enterprise.

A.J. “Jim” Teague, CEO of Enterprise’s general partner, commented that abundant U.S. natural gas liquids (NGL) production has made the U.S. a leading global source of ethylene and has spurred an “unprecedented buildout of mostly ethane crackers” on the Texas and Louisiana Gulf Coast.

“Including a second wave of new petrochemical plants now being developed, production of ethylene is poised to continue growth and is expected to exceed 100 billion pounds per year by 2025,” noted Teague. “We are very pleased to join forces with Navigator to bring this new terminal to fruition, which complements Enterprise’s integrated pipeline and storage network, including the development of open market hubs for ethylene and polymer grade propylene that help ensure price transparency, reliability and flexibility for petrochemical producers and consumers.”

Enterprise stated the new terminal includes two docks and can load 2.2 billion pounds per year of ethylene. The firm added that a refrigerated storage tank for 66 million pounds of ethylene is under construction at the site and will enable the facility to load ethylene at a rate up to 2.2 million pounds per hour. It projects tank construction to conclude in the fourth quarter of this year.

In addition, Enterprise noted the terminal is linked via pipeline to the company’s NGL storage complex in nearby Mont Belvieu. The company noted that it is commissioning a high-capacity ethylene salt dome storage well at the Southeast Texas hub that will be able to store 600 million pounds of the petrochemicals feedstock. It contends the system will serve as an open market storage and trading hub for the ethylene industry.

“By domestically manufacturing these products, highly skilled American jobs are created while at the same time the sale of the petrochemical gases to international customers generates favorable balance of trade and payments,” Butters said, referring to intermediate petrochemical gas products such as ethylene and propylene. “We expect this trend of exporting intermediate petrochemical gases to accelerate, benefiting our specialized tankers. Furthermore, we are working in the development of domestic and international infrastructure projects that will facilitate this important trend.”

Enterprise also stated that it will further extend its ethylene pipeline and logistics system into South Texas via two projects:

  • A 24-mile pipeline linking Mont Belvieu and Bayport, Texas, via Morgan’s Point that should begin service in the fourth quarter of this year
  • The 90-mile Baymark Pipeline that it is building from Bayport to Markham, Texas, and should be completed during the fourth quarter of this year.

According to Enterprise, the new pipelines – supported by long-term customer commitments – will provide access to the Enterprise open market ethylene storage and trading hub for producers and consumers throughout Texas.

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Good parent good child, bad parent bad child, good parent bad child, bad parent good child LOL

_________________________________________________________________________________

 

TenEx develops NoHit tech for shale well issues

 

 

As US shale wells fall short of production projections by 15 percent to 40 percent, exploration and production companies are drilling more wells on their acreage to compensate. These new “child” wells, drilled in close proximity to an existing “parent” well, can damage the parent and themselves be less productive than prior wells. The parent-child interference happens because the parent wells create a pressure sink in their production zone, encouraging child fractures to propagate to depleted rock instead of virgin rock.

In some of the most productive basins, most drilling in 2020 will be child wells. This

will bring a higher cost per barrel for the child well and a weaker new decline curve for the parent well. Lease depreciation will likely result, affecting the borrowing capacity of E&Ps and their ability to drill new wells, according to TenEx Technologies.

In response, TenEx Technologies has developed a trademarked NoHIT, a patent-pending frac hit mitigation chemical technology which is the first of its kind in the industry. NoHIT is pumped as an additive to a parent well’s preload and/or active loading program, to temporarily pressurize the depleted rock and increase its associated rock stress.

“NoHIT represents an important tool for operators as US shale drilling enters a new phase in which a lot of the prime acreage is becoming saturated with wells. NoHit should extend the life of existing acreage by allowing infill wells to produce more oil and cause less damage to surrounding wells,” says Eric Foster, CEO of TenEx Technologies.

By pressurizing the depleted rock around the parent, NoHIT discourages child fractures from communicating with the parent fractures, thereby protecting the parent, and it encourages those fractures to target new reservoir. This helps the child well achieve its modeled production.

Using NoHIT, E&Ps can gain additional production from their acreage and reduce their cost per barrel.

 

 

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Ceo, is there some reason that you simply can’t post the relevant links?

  • Haha 1
  • Upvote 1

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4 hours ago, Douglas Buckland said:

Ceo, is there some reason that you simply can’t post the relevant links?

Is easy to copy/paste me thinks. Some is relevant, a lot is just what ceo thinks is important I guess??

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7 hours ago, Douglas Buckland said:

Ceo, is there some reason that you simply can’t post the relevant links?

Sometimes what he's posting is hidden behind a paywall 

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17 hours ago, Douglas Buckland said:

Ceo, is there some reason that you simply can’t post the relevant links?

Yes subscriptions..for many articles and posts the link wont work unless you subscribe, for others that are in my email, the links dont work so copy and paste is the only option.

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9 hours ago, Ward Smith said:

Sometimes what he's posting is hidden behind a paywall 

Yes.. thanks

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(edited)

23 hours ago, Old-Ruffneck said:

Here's a good read @ronwagn

Thank you. This just shows what Trump and good governance are up against with the Demoncrat bureaucrats. Hopefully four more years will help get things straightened out. We need to eliminate a lot of their jobs. Meanwhile Texas is allowing unlimited flaring on the other side of the extremes. 

Also, natural gas is lighter than air so it is difficult to see it remaining on the ground. There has never been an LNG carrier ship explosion or one related to loading or offloading, to my knowledge. 

Edited by ronwagn
addition

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Is the US Shale Boom Really Slowing Down?

 

Since taking flight in 2008, the American shale oil revolution has probably been the biggest energy story since the end of World War II. U.S. crude oil production has leaped 160 percent to almost 13 million b/d. Shale has transformed global energy markets and obliterated the long-held notion that U.S. crude production peaked in 1970 at 9.7 million b/d.

In fact, thanks to shale, the U.S. has accounted for almost all new global oil production over the past five years. For 2019 alone, the shale industry added some 1.2 million b/d of crude, enough to even cover new global demand.

The emerging question now is whether or not the U.S. shale oil boom is slowing down. In truth, however, the more poignant question is whether or not the industry is just “growing more slowly.” Indeed, these are fundamentally different questions that too often get conflated. Regardless, already accounting for a rising 80 percent of U.S. crude production, without shale there may be no new U.S. supply.

For sure, rapid shale well decline rates mean more drilling, higher debt, and smaller profits. The question of peaking shale though really lies in West Texas’ Permian basin. The Permian is now one of the largest oilfields in the world and accounts for over 35 percent of U.S. crude production. The Permian though has some 3-4 million b/d of new pipeline capacity coming within the next few years, with numerous additional gas pipelines meaning less flaring and more oil.  

Further, if oil prices can stick above $65 or $70, U.S. shale would be given the proverbial “shot in the arm” to better its finances. Such low prices in recent years have already forced the industry to slash costs and greatly increase efficiency. Many producers have sharpened their knife so much that they have breakevens in the $40 range. 

But the real driving force behind more U.S. oil production is the ongoing importance of oil.  Let us be clear: oil supplies some 33 percent of global energy and projections of absolutely declining demand are speculation since oil currently has no material substitute. Although lower in 2019, global oil demand usually rises at 1.3 million b/d.

Any slower growth in oil demand comes more from slower economic conditions than any structural change. Electric cars are overstated since they are not affordable. The average Tesla buyer, for instance, makes a whopping $400,000 per year. The rise of gas-guzzling SUVs in the still developing nations will likely compensate for oil demand reductions that come from electric cars.

Indeed, an ever-expanding U.S. oil export complex will mandate more domestic production. We already know that the oil is there: in December 2018, the “largest U.S. oil and gas discovery ever” was made in the Permian basin. Nationally, proven reserves have more than doubled over the past decade to 65 billion barrels. The resource available is many times that.

To be sure, however, such high growth rates for U.S. crude production like we have seen in recent years cannot be maintained. With significant CAPEX reductions, some see output rising in 2020 at less than half the rate of 2019. Farther out, IEA still has the U.S. supplying 85 percent of new global crude in the 2020s. A peaking at 16 million b/d for total U.S. crude output seems possible, but do not expect drastic declines in the absolute sense. Oil is just too important, and we simply have too much of it.  

Ultimately, beyond shale, the next U.S. oil revolution could be one that not even the industry itself is promoting enough. This would be the widespread deployment of CO2-EOR technologies. This tertiary oil recovery process centers on capturing anthropogenic CO2 from industrial facilities and pumping it safely into the ground to lower the viscosity of the crude left after primary and secondary operations. CO2-EOR is a net carbon reducer and importantly has been supported by the Intergovernmental Panel on Climate Change.

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U.S. oil production hits estimated record 13 million barrels per day

U.S. crude oil production rose to an estimated record-high of 13 million barrels per day last week as the nation's energy growth crossed a new threshold, according to a weekly report from the U.S. Energy Department.

The increase production comes as the nation's stockpiles of commercial crude oil fell by 2.5 million barrels last week, but those volumes were more than offset by large spikes in gasoline and other fuel supplies.

The United States' total petroleum inventories rose by 14.5 million barrels last week as gasoline stocks jumped by 6.7 million barrels and distillate fuel oil supplies - used to make diesel and heating oils - spiked by 8.2 million barrels, according to the inventories report.

U.S. crude production increased from 12.9 million barrels a day - where it had sat for a few weeks - up to the new 13 million barrels mark.

 
 

The news comes amid falling oil prices as the U.S. benchmark could settle below $58 per barrel for the first time since Dec. 3.

 

 

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NEW YORK (Reuters) - U.S. crude oil production is expected to rise by 1.06 million barrels per day (bpd) in 2020 to a record of 13.30 million bpd, the U.S. Energy Information Administration (EIA) said on Tuesday, above its previous forecast for a rise of 930,000 bpd.

The output in 2021 is forecast to rise by 410,000 bpd to 13.71 million bpd, according to the EIA.

“We forecast U.S. crude oil production will reach new records in 2020 and 2021, driven primarily by higher production in the Permian region of Texas and New Mexico,” EIA Administrator Linda Capuano said in a statement.

“Both global oil supply and consumption are expected to grow in 2020, with supply from non-OPEC producers, particularly the Unites States, Norway, Brazil, and Canada, more than offsetting declining production from OPEC.”

 

A shale boom has helped make the United States the world’s biggest oil producer, overtaking Saudi Arabia and Russia.

However, the rate of growth is expected to slow into next year as U.S. oil producers follow through on plans to slash spending on new drilling for a second year in a row in 2020.

In 2019, the oil rig count, an early indicator of future output, notched its first annual decline since 2016 as independent exploration and production companies cut spending on new drilling as shareholders seek better returns in a low energy price environment.

 

For 2020, the agency expects U.S. petroleum and other liquid fuels demand to climb 160,000 bpd to 20.64 million bpd in 2020, below its previous forecast for a rise of 170,000 bpd to 20.75 million bpd.

Demand is expected to rise 70,000 bpd to 20.71 million bpd in 2021, the EIA said.

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On 1/6/2020 at 4:49 PM, ceo_energemsier said:

Stimulating Future

Positive results are emerging from fracturing field laboratories.

 

 

John Duda and Cassie Shaner, NETL
Mon, 01/06/2020 - 11:00 AM

 

 

Hydraulic fracturing has come a long way as a means of stimulating oil and natural gas reservoirs since its first experimental use in the 1940s, thanks in large part to revolutionary technological advances led by the U.S. Department of Energy (DOE) that helped usher in the modern shale gas boom.

Natural gas derived from shale formations accounts for the bulk of U.S. natural gas production, rising from 1.3 Tcf in 2007—the first year for shale-specific record-keeping by the U.S. Energy Information Administration (EIA)—to 18.6 Tcf in 2017. Production from shale formations and tight oil plays is expected to rise to roughly 33.3 Tcf by 2050, accounting for more than 75% of the natural gas produced nationwide.

Because of plentiful domestic shale gas produced using hydraulic fracturing techniques, the U.S. led the world in natural gas production in 2018, notching record growth and setting a new annual production benchmark.

The DOE’s National Energy Technology Laboratory (NETL), the nation’s only federal research laboratory dedicated to fossil fuels, has a rich history of innovation when it comes to hydraulic fracturing. In the 1970s, fears that U.S. natural gas resources were dwindling prompted federally sponsored research focused on unconventional natural gas reservoirs, such as gas shales, tight sandstones and coal seams that were previously uneconomical to develop.

As part of the Eastern Gas Shales Research Program, the NETL helped to advance large-volume hydraulic fracturing technology. In 1975 a DOE industry joint venture drilled the first directional wells in the Appalachian Basin to tap shale gas and, shortly thereafter, completed the first horizontal shale well that used seven individual hydraulically fractured intervals. The DOE integrated basic core and geologic data from 35 research wells to prepare the first publicly available estimates of technically recoverable gas for gas shales in West Virginia, Ohio and Kentucky.

Today the NETL is building upon that legacy via collaborative investigation of ways to increase resource recovery efficiency. Field laboratories within the Permian, Appalachian, Williston and Eagle Ford basins are shedding light on subsurface questions associated with unconventional reservoirs and providing meaningful insights to help meet the energy needs of future generations.


Marcellus Shale Energy and Environmental Laboratory

Established in 2014, the Marcellus Shale Energy and Environmental Laboratory (MSEEL) was among the DOE’s first field laboratories. The $25 million project was created to develop and validate new knowledge and technology to improve recovery efficiency and minimize the environmental implications of unconventional resource development.

The NETL manages the project and provides technical oversight on behalf of the Office of Fossil Energy. The MSEEL, which spans two Northeast Natural Energy (NNE) production sites outside Morgantown, W.Va., is run by nearby West Virginia University (WVU) and involves a consortium of other universities and national laboratories.

The initial site at the Morgantown Industrial Park (MIP) featured two wells, which provided a well-documented baseline of production and environmental characterization data. A dedicated scientific observation well was drilled to collect detailed subsurface data, including log data. Operators collected 111 ft of 4-in. whole round core, believed to be the first core extracted through the entirety of the Marcellus Formation.

In addition, 147 sidewall core samples were taken, which researchers used to conduct geochemical, microbiological and geomechanical investigations. The observation well also was instrumented with a downhole seismic array to monitor stimulation events in two new production wells (identified as MIP 3H and 5H) that NNE began drilling in late June 2015. The MIP 3H lateral was logged and instrumented with permanent fiber-optic sensors. 

NNE recently established a second MSEEL location, known as the Boggess site, featuring six horizontal production wells—all logged with the latest LWD tools and including one fully instrumented with permanent fiber-optic wiring and sensors to provide near-real-time information during fracturing and production.

The initial project plan called for sample and data collection as well as testing and demonstration of advanced technologies. But the project’s phased approach and access to multiple Marcellus wells provided the flexibility to expand the project’s scope by identifying and incorporating innovative new tools and techniques focused on increasing recovery efficiency.

Lessons learned from the MSEEL within the past five years have increased reserves at the MIP well site by 20% and contributed to best practices that NNE incorporated into its other operations. Other operators in the Appalachian Basin are adopting state-of-the-art techniques and technologies that have been demonstrated and confirmed as part of this project. For example, the use of 100 mesh sand proppant and synthetic drilling mud has become a common practice throughout the basin. 

MSEEL's Boggess site The MSEEL’s Boggess site, established in 2018, features six horizontal production wells, including one fully instrumented with permanent fiber-optic wiring and sensors to provide near-real-time information during hydraulic fracturing and production. (Source: NETL)

Completion design
The MSEEL team developed an engineered design methodology for well completion that enhances effectiveness by increasing the percentage of perforation clusters along the lateral contributing to production. The methodology—based on core sampling, fiber-optic sensing and LWD data—minimizes the effect of lateral heterogeneity on fracture stimulation. These measurements are used to predict breakdown pressure, which was then used to place stages and perforation clusters in rock with similar mechanical properties, thereby improving the probability of stimulating all clusters within a given treatment stage.

Perforation impacts on productivity
Research at the MSEEL site indicated that fewer perforations are needed per stage than had been previously used. By using fewer and smaller holes, NNE was able to increase the rate of injection, which facilitated more efficient fracturing by delivering sand more effectively into the induced cracks. Coupled with this, NNE learned that upgrading the casing string and frac stack to withstand higher pressures more effectively ensured that every perforation cluster was stimulated effectively.

Vehicle impacts
NNE learned that silica exposure can be controlled by using a cost-effective box-type sand delivery system versus a standard truck-and-trailer system. This is another technique widely used throughout the basin. Researchers also learned that a natural gas hybrid rig does not reduce emissions as much as previously believed, nor does it provide significant cost savings.

Drilling mud
The MSEEL provided confirmation that synthetic drilling mud produces cuttings that are more environmentally friendly to dispose of than traditional cuttings and improved drilling performance. This type of mud is commonly used by NNE and other operators in the basin. 

Recovery efficiency
Fiber optics and production logging proved that increased 100 mesh sand concentrations do not degrade reservoir performance when compared to larger sand proppant. It improves both fracture stimulation and decreases costs as more sand can be shipped per container volume. NNE uses a much higher percentage of 100 mesh sand as part of its standard frac design.

Fracturing and efficiency
WVU developed a software system called FIBPRO to analyze fiber-optic distributed acoustic sensing, distributed temperature sensing and microseismic data collected during hydraulic fracturing of the MIP 3H well. Analyses using FIBPRO showed that the distribution of deformation and crossflow between stages demonstrated differences in completion efficiency among stages and clusters. These differences affected production efficiency and resulted in a better understanding of the geological/geomechanical controls on completion and, ultimately, on well production.

Fracture geometry
WVU developed an integrated geomechanical and discrete natural fracture model to investigate the complexity of hydraulic fracture geometry. History matching and production response, as measured by fiber-optic data and production logging, confirmed the reservoir simulation and importance of engineered hydraulic fractures. Well spacing sensitivity research was done to identify the optimal distance between laterals to maximize recovery and the number of wells per section.

Numerical modeling was conducted to simulate stimulation Stages 1 through 3 of the MIP 3H well, using measured injection data. Comparison of measured data and slurry volumes, slurry rates and proppant mass estimated by the model showed strong correlation with stimulation efficiency. This modeling will continue for other stages, incorporating microseismic and production spinner test data, to better model fracture geometries.

Geochemistry
New microorganisms have been recognized in the deep biosphere represented by the Marcellus Shale. Subsurface microbial communities affect energy production, reservoir properties and wellbore integrity through processes such as biomineralization (scaling), acid formation (corrosion), biofilm formation (biofouling) and metal mobility. Understanding these organisms is important to reduce downhole well damage and scaling as well as precipitation of radium in surface facilities. To better analyze the biogeochemical characteristics of Marcellus Shale and investigate geological controls on microbial distribution, diversity and function, researchers developed new methods to maximize recovery and reproducibility of lipid biomarkers—efforts that are enhancing researchers’ understanding of subsurface biogeochemistry and the effect on long-term production. Researchers at the NETL have investigated water/rock interactions and the effects of barite precipitation on production efficiency.

Water impacts
Continuous monitoring of flowback and produced waters for nearly a year showed that total dissolved solids leveled off, with little change in ionic composition. Radionuclides in the drill cuttings were consistently below West Virginia Department of Environmental Protection levels for landfill disposal and well below U.S. Department of Transportation levels for classification as low-level radioactive waste. Findings from the analysis of the MSEEL drill cuttings aided West Virginia legislators in establishing new statewide waste disposal criteria based on the U.S. EPA’s toxicity characteristic leaching procedure, which has not been exceeded for either organic or inorganic constituents in the MSEEL drill cuttings.

Emissions
Direct-reading aerosol sampling was conducted throughout all stages of well development at the MIP site except pad preparation. Sampling locations included the drill pad, 1-km and 2-km distances. EPA-regulated PM2.5 (particles less than 2.5 micrometers in diameter, capable of reaching human lung airspaces) emissions were not detectable from background at 1-km downwind during the highest emissions periods (hydraulic fracturing) on the well pad. Monitoring during drilling and completion operations indicated that a significant portion of air emissions was from truck traffic and other mobile sources, not from emissions due to pad operations. Emissions audits conducted at the MIP site using stationary and mobile systems indicated that the primary contributor to methane emissions on site was a produced water tank.

Next steps
Continued work at the MSEEL’s two sites builds upon the revelations and achievements of the project’s earlier work, with a focus on economics.

The initial efforts at the MSEEL advanced hydraulic fracturing stimulation techniques that the NETL researchers pioneered years ago. The current R&D is geared toward cost-effectively improving gas recovery from horizontal drilling and hydraulic fracturing in the region. A key objective of the latest field test is to demonstrate optimal completion strategies that can be applied to other areas of the Marcellus Shale play to improve overall resource recovery efficiency. 

For example, modeling from nanopore to reservoir-scale by WVU at the original MSEEL site advanced the understanding of the frac response and affected rock volume and the approaches and capabilities to handle and process large datasets from a single well. It also helped optimize spacing between laterals, stage length and cluster design. Technologies advanced at the MSEEL enabled NNE to design better wells. In addition, several technologies have been developed since the MSEEL began that facilitate acquisition of the same type of information much more cost-effectively when coupled with advanced modeling. That is the critical focus of the MSEEL project’s next phase. 

The NETL and its project partners also are building better models that offer deeper insights. A team of NETL researchers is conducting computed tomography imaging and logging 139 ft of 4-in. whole round core and 50 sidewall cores retrieved from the Boggess site’s 17H pilot well. The data will be used to develop a high-resolution geomechanical model of the Marcellus that could yield the capability to improve production efficiency and environmental performance throughout the Marcellus Shale region.

Work at MSEEL’s Boggess site near Morgantown, W.Va., is focused on learning from prior research and integrating the latest innovations to improve resource recovery and project economics while reducing environmental impacts. (Source: NETL) Work at MSEEL’s Boggess site near Morgantown, W.Va., is focused on learning from prior research and integrating the latest innovations to improve resource recovery and project economics while reducing environmental impacts. (Source: NETL)

The MSEEL project demonstrated a model government-private sector partnership, with WVU at the helm. The project has shown that safe and efficient operations can be conducted with no long-term environmental consequences. Because of NNE’s successful demonstration of technologies and techniques, these practices have been adopted by other operators in the basin.


Hydraulic Fracturing Test Sites 1 and 2

The NETL teamed up with the Gas Technology Institute (GTI), of Des Plaines, Ill., in 2014 to launch a comprehensive diagnostics and testing program focused on reducing  and minimizing environmental impacts, demonstrating safe and reliable operations, and improving the efficiency of hydraulic fracturing. The research collaboration is focused on two hydraulic fracturing test sites (HFTS 1 and HFTS 2) about 140 miles apart in the Permian Basin of West Texas and New Mexico. The program emulates field experiments that the DOE/NETL and the Gas Research Institute—one of two entities that combined to form GTI—performed in vertical wells in the 1990s.

Technology has evolved to favor longer horizontal shale wells with multiple hydraulic fracturing stages, introducing a new set of challenges and unanswered questions. For instance, the optimal number of fracturing stages during multistage fracture stimulation in horizontal wells is unknown. Multistage fracturing in horizontal wells raises costs, yet the increase in fracturing stages does not always correlate to a rise in production.

Applying a uniform fracture stimulation design to all stages does not account for geological variations along the wellbore, and efficiency is not maximized. Improvements in the design and execution of fracturing processes will reduce the number of infill wells to be drilled, the amount of working fluid used and energy demand for future oil and gas recovery activity.

Optimization of the fracturing process requires an understanding of the cause-and-effect relationship between fracturing parameters and geological properties at a given location along the wellbore. A comprehensive understanding of the quantifiable impacts of a shale’s geomechanical and depositional features is required to design and implement an optimal hydraulic fracturing strategy. Researchers at HFTS 1 and 2 are conducting conclusive tests designed and implemented using advanced technologies to characterize, evaluate and improve the effectiveness of individual hydraulic fracture stages.

Laredo Petroleum provided a field site in Reagan County, Texas, for the $32 million HFTS 1 project. The site features 11 horizontal wells in the Wolfcamp Formation of the Permian-Midland Basin. Prior to and after hydraulic fracturing operations, researchers with GTI conducted seismic surveys to produce images of the subsurface geology, collected water and air samples and undertook microseismic monitoring to detect very small-scale seismic events that occurred as a result of fracturing.

In addition, researchers used tracers to study the distribution of proppant. While all planned Phase 1 fieldwork for HFTS 1 has been completed, data analysis and integration are ongoing. Additionally, pressure, temperature and production data from the test wells continue to be collected for future analyses. The information gathered through the project is the most meaningful dataset to date for unconventional oil and gas production, providing information essential to understanding induced fractures, validating and developing models, and assessing how predictive analytics can improve the process.

The $27 million HFTS 2 project was initiated in 2018. Anadarko Petroleum Corp. and Shell Exploration and Production Co. agreed to host a new field site in Loving County, Texas, within the Permian-Delaware Basin, that features different depths, pressures and permeability than HFTS 1.

As of mid-2019, all wells on the eight-well pad were drilled, and two were fitted with fiber-optic sensors. An additional vertical pilot well was drilled, cored and instrumented with permanent fiber-optic cable and pressure gauges. Fracturing operations were underway, with associated analyses pending.

While the goal of HFTS 1 was to understand and define the relationships of shale geology and fracture dynamics, HFTS 2 is focused on optimizing hydraulic fracturing and well spacing.

The NETL-funded HFTS 1 and HFTS 2 are located about 140 miles apart in the Permian Basin of West Texas and New Mexico. (Source: NETL) The NETL-funded HFTS 1 and HFTS 2 are located about 140 miles apart in the Permian Basin of West Texas and New Mexico. (Source: NETL)

Impacts of fracturing operations
More than 400 fracture stages were completed in the 11 wells at HFTS 1. The core description was completed by multiple teams, and results have been incorporated into a final core description report. Two main sets of natural opening-mode fractures filled with calcite cement were identified, trending broadly northeast to southeast and west-northwest to east-southeast. Eleven faults were identified, all within the Upper Wolfcamp Formation. More than 700 fractures (natural and induced) were identified in the core.

Fracture insights
Results indicate that fracture quantity and complexity are far beyond what current simulators/models can predict. Stimulation creates multiple far-field fractures (100 ft away), which are not uniform in distribution with fracture clusters and voids. Variable-rate fracturing provides an uplift to production by improving perforation efficiency without adding extra costs. 

Air and water impacts
Air and water samples were collected prior to, during and after hydraulic fracturing operations. Air quality data and analysis indicated a little-to-no increase in regulated air quality compounds during fracturing and production operations at the test site, though there is potential for elevated emissions during flowback when open systems are used. In addition, there was no evidence of natural gas or produced water migration to the groundwater aquifer. Research to date shows that hydraulic fractures do not grow into freshwater zones.

Proppant impacts
Vertical proppant distribution measured in the core is only a fraction (5%) of the measured microseismic geometry. Multiple proppant packs were found. Others were likely washed out during coring, indicating inefficient proppant placement. Propped fracture dimensions are very different from hydraulic fracturing dimensions.

Geological distinctions
A slant core well was successfully drilled through the stimulated rock volume between two horizontal wells, recovering 595 ft of core spanning the upper and middle portions of the Wolfcamp Formation. This was the first such core ever taken as part of a publicly funded research project. Analysis indicated that the Upper and Middle Wolfcamp formations vary considerably. The Upper Wolfcamp features many times more hydraulic and natural fractures, leading to very different fracture half-lengths and spacing implications.

Fracturing & production

Variable-rate fracturing provides an uplift to production by improving perforation efficiency without adding extra costs.

A proppant pack is shown in a hydraulic fracture of an Upper Wolfcamp Formation core. (Source: NETL) A proppant pack is shown in a hydraulic fracture of an Upper Wolfcamp Formation core. (Source: NETL) Core samples from HFTS 1 show unique distinctions between natural fractures and those produced via hydraulic fracturing. (Source: NETL) Core samples from HFTS 1 show unique distinctions between natural fractures and those produced via hydraulic fracturing. (Source: NETL)

Next steps
The HFTS projects are capturing fundamental hydraulic fracturing insights that will influence the exploration and development of different shale formations for many years. Researchers are continuing to analyze and integrate various datasets to gain an enhanced understanding of the fracturing process.

As the primary research work at HFTS 2 proceeds, HFTS 1 has moved on to Phase 2, which focuses on EOR methods. The EOR field pilot involves a new set of wells about 1 mile northwest of the existing Phase 1 experimental wells, with an updated completion design that reflects lessons learned in Phase 1. The site includes a central injector/producer to test cyclic gas injection, offset by horizontal and vertical wells equipped with downhole pressure and temperature gauges used to monitor gas movement during injection in the reservoir.

Both HFTS projects offer an immediate impact to the industry because each effort involves a joint industry partnership (JIP) composed of more than a dozen oil and gas companies and operators (including six involved in both projects) that provide technical support and share costs. The JIPs will accelerate the adoption of technology innovations and best practices being developed.


Bakken/Eagle Ford Laboratories

As hydraulic fracturing methods continue to evolve and allow improvements in stimulated volume, a large percentage of recoverable oil remains in the ground after IP. The NETL partnered with the University of North Dakota’s Energy & Environmental Research Center (UND-EERC) to initiate an EOR-focused field laboratory
project at the Stomping Horse complex within the Williston Basin’s Bakken Shale play in western North Dakota. The collaboration began in September 2017.

Preliminary laboratory investigations suggest that ethane and mixtures of methane and ethane may be used to mobilize oil from the Bakken reservoir and be viable injectate for tertiary EOR operations. The EERC engaged Liberty Resources and the North Dakota Industrial Commission, through the Bakken Production Optimization Program, to design and conduct an EOR pilot test using rich gas. The primary goal of the project, along with the newer Eagle Ford Shale Laboratory launched in 2018, is to better characterize existing fracture networks, stimulated reservoir volume and fluid flow dynamics to improve EOR opportunities.

Baseline reservoir characterization data collection has been completed for all wells within the Leon-Gohrick drill spacing units in the Stomping Horse complex. Parameters measured included analysis of produced oil, water and gas as well as bottomhole pressure and temperature for wells permitted for injection and offset wells.

Pressure
Minimum miscibility pressure (MMP) studies have been conducted to determine the MMP of rich gas components and different rich gas mixtures in oil from the Stomping Horse complex. MMP data for methane, ethane, propane and different relevant mixtures have shown that “richer” gas mixtures will result in lower MMP values (e.g., methane MMP > ethane MMP > propane MMP).

Types of injection gas
Rock extraction studies of the rich gas components on Bakken shale and nonshale samples show that, when it comes to mobilizing hydrocarbons from Bakken rocks, methane is the least effective, propane is the most effective and ethane has an intermediate effect. The rock extraction studies also show that propane is effective at all pressures; ethane is effective at higher pressures and methane is the least effective at any pressure.

Modeling studies
Modeling-based studies of the potential effects of rich gas EOR operations on the surface infrastructure of the Stomping Horse complex predict that the process will not adversely affect surface facility operations. Reservoir modeling of selected injection/production scenarios predicts that incremental oil recovery may exceed 25%.

Injection testing
Small-scale injectivity tests were conducted in two wells in the Stomping Horse complex during summer 2018. A total of 24.6 MMscf of rich gas was injected during three tests. The maximum injection rate achieved was 1.14 MMscf/d. Downhole pressure and temperature data were collected before, during and after the injection tests from six wells in the drill spacing unit, including the injection wells and the immediately adjacent offset wells. Data obtained from the small-scale injection tests were used to refine the design of the subsequent larger pilot tests.

Fast flow pathways
A tracer was introduced to the injection well during large-scale pilot tests. Multiple sampling events from multiple wells were conducted in the Stomping Horse complex as a means of identifying fast flow pathways between the injector and various offset wells. The maximum injection rate for the large-scale test is 2 MMscf/d. In general, each cycle injection is conducted until one of three criteria is achieved: total injection of 60 MMscf, 30 days of injection or clear evidence of substantial breakthrough at an offset well.

Next steps
Management of rich gas production from the Bakken is a high priority for government and industry stakeholders in North Dakota, due to economic challenges associated with expanding gas-gathering infrastructure in the relatively geographically isolated location. The NETL’s efforts with UND-EERC aim to demonstrate the viability of using rich gas for EOR in the Bakken, which would result in reduced flaring and improve oil recovery.

A pilot injection test and associated monitoring activities are ongoing, and shale permeability and shale sorption studies, using a flow-through testing approach, continue. The effects of rich gas exposure on the properties of Bakken shale and nonshale tight rocks, including clays and mineralogy, wettability and relative permeability, are being examined using a variety of laboratory techniques, such as nuclear magnetic resonance and field emission scanning electron microscopy. The potential for preferential sorption of different rich gas components in Bakken rocks also is being examined using flow-through experiments under reservoir pressure and temperature conditions.

Similarly, the emerging Eagle Ford Shale Laboratory seeks to improve the efficiency of oil and gas recovery from hydraulically fractured horizontal wells on INPEX Eagle Ford LLC’s shale properties in LaSalle County, Texas. The project teams Texas A&M University with Lawrence Berkeley National Laboratory and Stanford University. Funding is provided by the NETL, with a match from INPEX Eagle Ford LLC and contributions by other operators and service companies via a JIP agreement.

Field-based research within the Eagle Ford Shale formation began in April 2018 and is ongoing. Using newly developed and comprehensive monitoring solutions, the team will deliver unprecedented and comprehensive high-quality field data to improve scientific knowledge of the hydraulic fracturing process, refracturing and subsequent huff-and-puff gas injection. This knowledge will facilitate optimized production from a reduced number of new wells, with less material and energy use.


Key Takeaways and Future Steps

The research conducted by the NETL’s field laboratories has helped to redefine the public’s perception of unconventional oil and natural gas exploration by delivering an unbiased view of the environmental impacts of the drilling and stimulation processes, which research has demonstrated to be relatively benign. Simultaneously, the NETL is identifying new possibilities for hydraulic fracturing technologies that offer the potential to optimize operations and boost resource recovery beyond current levels.

For instance, several technologies have been developed since the MSEEL began that, when coupled with advanced modeling, could allow the acquisition of the same type of information in a much more cost-effective way. If the project’s current efforts prove that these innovations work and lead to improved production results, the project will lead to more efficient and effective resource recovery within the Marcellus Shale region and possibly throughout other shale plays nationwide—particularly when combined with insights from HFTS 1 and 2.

The Phase 2 work at HFTS 1 complements the EOR field research underway at the Bakken laboratory site. Each project ultimately seeks to improve the effectiveness of shale oil production by providing new scientific knowledge related to stimulation and production as well as enhanced recovery via refracturing and EOR.

Research by the NETL and its partners is providing new insights into the fracture stimulation and EOR processes, which will aid in the development of new methodologies and tools to maximize the production of oil from fractured shale. While some research results will apply to specific formations, many realistic and practical learnings will be applicable to other unconventional plays and subsurface applications, such as tight gas sand reservoirs and even saline formations for CO2 storage.

The DOE is using data collected from these demonstration projects and new field laboratory projects awarded in fiscal year 2019 to support artificial intelligence and machine learning. The results of this work will yield fundamental knowledge of shale fracture and matrix properties. Additionally, analytical tools for assessing hydraulic fracture performance and methods of targeting distinct features of the hydraulic fracture system will be developed to improve production efficiency and increase resource recovery.

 

This post must blow the minds of the “no tech we been fracking for decades” boys. Hehe

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They have been fracking for ages, but not like this.

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