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E&P Notes

Fracturing by the Numbers: A Complex Balance

Stephen Rassenfoss, JPT Emerging Technology Senior Editor

For those in shale exploration, “fracability” is a real word, a critical property, and a point of contention.

Fracability has entered the vocabulary of exploration because it is critical for exploration to know if rocks will produce when hydraulic force is applied. It can be a divisive concept, in part because there are a lot of ways to determine fracability, with dueling test methods and multiple equations offered by experts in petrophysics and geomechanics.

A University of Oklahoma team is trying to bridge that gap using widely available information on the makeup of rocks and their properties to generate a fracability rating. It is a difficult challenge because a single grade needs to reflect a lot, from petrophysical properties, such as the presence of brittle minerals, to geomechanical ones, such as the toughness of the rock.

“It is a new definition based on petrophysical and geomechanical properties,” said Xiaochun Jin, who came up with the system while he was a graduate student at the University of Oklahoma.

The one word used to describe what makes a rock fracable is “brittle.” Yet that is sometimes a point of dispute: according to an SPE paper on the work, “there is no universal agreement regarding its definition.”

The paper lists 22 formulas for brittleness based on laboratory testing and well logs. Brittleness matters when trying to fracture rocks to create productive pathways for oil and gas to flow out. A rock with high clay content is likely to be a poor target because it would bend rather than break. The university team’s attempt at settling the argument adds another definition of mineral brittleness based on several widely used measures.

The new system, developed with the assistance of two professors—Subhash Shah and Jean-Claude Roegiers of the Mewbourne School of Petroleum and Geological Engineering at the University of Oklahoma—tries to account for both a rock’s brittleness and strength, which determines the energy needed to break it up.

Brittleness alone has its limits, Jin said. There are highly brittle rocks, like dolomitic limestone, that can act as a barrier, while others are not so brittle, but can be successfully fractured because they are not very strong. Jin said he hopes this will allow explorers to better locate wells and target the most productive layers of thick zones that are most fracable, and to better control fracture growth when hazards are present, such as an aquifer that could flood the well.

The first step in the process is to calculate brittleness using three proven formulas from the list. Each formula can be calculated using well logging data, which costs less than lab testing and requires less time to gather. The next step is to combine that data with one of four other measures of rock properties, most likely Young’s modulus or fracture toughness.

The result of this formula is a fracability index score from 0 to 1. A rating of 0 denotes the perfect fracture barrier, and a 1 signals the best rock for fracturing. A formation with an index number around 0.65 is a good candidate, though further research may lower the boundary somewhat and simplify the calculations.

While the university is working to patent this method, the team is seeking data from operators and service companies on rock properties and production to see how it would have performed as an exploration tool and refine it.

The goal is to reach a broad group of users and perhaps settle some arguments. “We hope this can resolve the dispute over what is fracable,” Jin said.

For Further Reading

SPE 168589 Fracability Evaluation in Shale Reservoirs—An Integrated Petrophysics and Geomechanics Approach by Xiaochun Jin, Subhash N. Shah, Jean-Claude Roegiers, The University of Oklahoma et al. 

A Lighter UltraStrong Proppant

Oxane Materials has joined the 20,000 club—joining the two makers who have announced they are selling proppant capable of standing up to high pressures.

The new offering, called OxThor, meets the standard set for use in frontier fields, such as those in the Lower Tertiary trend in the US Gulf of Mexico, where the grain-sized spheres will be called on to prop open fractures in wells drilled in ultradeep water that are around 30,000 ft deep.

What is different is the weight of the Oxane offering. It is said to have a specific gravity of 3, compared to 3.9 for the new 20,000 psi offerings from Carbo Ceramics and Saint-Gobain. The current standard for extreme conditions is sintered bauxite, which goes up to 15,000 psi, which has a specific gravity of about 3.6. The new offering from Oxane is expected to be able to perform at temperatures up to 450°C, comparable to sintered bauxite and other proppant high in alumina.

The lower weight is an advantage in extremely hot reservoirs that break down gels used to thicken fracturing fluids, allowing it to carry proppant further, increasing its effectiveness, Oxane President Chris Coker said.

The three companies making 20,000 psi proppant are ramping up production to allow testing. Oxane is increasing the production of OxThor, with a goal of supplying enough for laboratory testing by customers in May, and a field test late in the year, he said.

Carbon Dioxide Reserves Could Alter US EOR Map

Growth in enhanced oil recovery (EOR) projects using carbon dioxide (CO2) in west Texas could be limited by supplies unless new sources of the gas are found in the ground or from indus-
trial facilities.

A recent report from the US Department of Energy (DOE) said that CO2 fields currently supplying west Texas, which has the largest concentration of EOR projects using carbon dioxide, can continue to produce at current levels for 10 to 20 years. That might be a constraint in an area where the number of potential projects could significantly increase demand.

The report suggested, however, that this is not likely a hard limit on the carbon dioxide in the ground. “The exploration for subsurface CO2 deposits is not well developed, as discovered CO2 deposits have generally been the byproduct of oil and gas exploration,” according to the report.

A second DOE report made a case for significantly more CO2 production not far from west Texas. The report on technically recoverable carbon dioxide estimated that the gas in place in the San Juan area in New Mexico could add 22.4 Tcf of CO2 production—more than half of the estimated potential resource nationally, according to the report. Another 11.4 Tcf in potential production was identified within the Val Verde area in Texas.

The search for potential reserves included areas where volcanic activity millions of years ago was likely to have left large amounts of CO2. The resource estimate was based on what could be technically recovered using available technology. Development will depend on whether the gas in the ground—the San Juan and Val Verde deposits range from 12,000 to is 15,000 ft deep—can be produced at a price that backers of EOR projects are willing to pay.

The study of currently available production focused on places likely to have production costs of no more than USD 20/bbl at the source. While field owners typically pay up to twice that amount, the cost of transport and compression adds to the cost.

In contrast, there is a lot of room for growth in the northern Rockies, where 67% of the nation’s 96.4 Tcf of economically recoverable natural CO2 is found in the Big Piney-LaBarge field, according to the report. While the formation is relatively deep, the high-pressure formations produce rapidly and also contain helium, a valuable commodity that can be sold to offset the cost of removing poisonous sulfur dioxide gas.

If oil prices rise enough to convince operators they can afford to pay more for the gas, the available reserve total will increase. The technically recoverable CO2 fields that could supply west Texas could supply the area for 30 years at current production rates.

For the reports, search online for Subsurface Sources of CO2 in the United States from DOE/NETL.

Colorado Emissions Control Rule Offers Some Flexibility

Colorado will become a testing ground for reducing emissions from oil and gas exploration and production (E&P). A new rule, known as Regulation 7, is an early effort at reducing E&P emissions and may help resolve a contentious issue in a state that combines rich unconventional oil and gas resources and significant opposition to how they are developed.

The addition of another regulation is not likely to be celebrated in the industry, but the collaborative process used to write the rule was praised by the head of one of the affected companies. “Hopefully, it is a new way to write a regulation,” said Doug Suttles, CEO of Encana, during his keynote address at the start of the IADC/SPE Drilling Conference and Exhibition in Fort Worth, Texas.

One of the advantages of the regulation—created by a coalition of government officials, environmental groups, and oil companies—is the flexibility it offers companies for how they meet goals to reduce emissions blamed for smog or global warming.

The result could create demand for proven technology, such as capture devices to reduce tank emissions and pumps that prevent natural gas from bleeding out, as well as new methods for detecting and reducing emissions.

Suttles predicted greater use of infrared cameras to detect airborne emissions as part of the required inspections needed to detect leaks. He said the new system could remove 92,000 tons of emissions a year in the Rocky Mountain state, or the equivalent of the pollution caused by every car in Colorado for a year.

The industry has a strong motivation to find lower-cost ways to discover and eliminate emissions. While capturing gas now leaking into the atmosphere can add to sales, the cost of doing so is still expected to be higher, Suttles said.

He said that the regulation will be re-viewed in 2 years to evaluate how it has per-
formed and determine if there are better, lower-cost ways of implementing it.