Small-Scale GTL Plants Could Offer Effective Solution for Production of Stranded and Unconventional North American Gas

September 18, 2019

Natural gas is the most hydrogen-rich carbon source available on earth, with more than 28,000 trillion cubic feet (Tcf) of marketable and technically recoverable gas worldwide. However, a large portion of this gas is in the form of unconventional gas (i.e., shale gas, tight gas, and coalbed methane), and production of unconventional gas requires a larger capital investment than does production of gas from conventional sources. This, along with low North American natural gas prices and limited transportation infrastructure, has forced producers to leave much of the unconventional and stranded gas resource underground—and to dispose of associated gas via costly reinjection into the reservoir or flaring into the atmosphere. To instead move this abundant energy resource to market in an economical and environmentally friendly manner, the industry should consider the gas-to-liquids (GTL) process.

Higher Full-Cycle Costs to Slow Permian Production, but Basin Cost to Remain Among Lowest in Industry

September 17, 2019

In recent years, the Permian basin has become one of the world’s largest oil-producing regions. Currently accounting for approximately 5% of global oil production, the Permian has a significant impact on the global oil supply-and-demand balance. However, signs exist that some sweet spots in the Permian have matured, leading to reductions in initial well productivity and increases in well decline rates. These signs raise the question: Will Permian production continue to grow in the next few years?

Higher Full-Cycle Gas Costs to Depress Mid-Continent Gas Production

September 12, 2019

The Mid-Continent and West Texas and Eastern New Mexico regions consist of the Arkoma (Fayetteville and Woodford shale gas), Anadarko (Cana Woodford shale gas and Granite Wash tight gas), Fort Worth (Barnett shale gas), and Permian basins. As producing wells in these tight-gas plays age, Mid-Continent non-associated gas is expected to decline over the 2020–2030 forecast period. However, condensate areas in the Permian will buck this trend.

Closing North American LNG Arbitrage

September 11, 2019

With the recent development of North American LNG exports, North American market pricing is now influencing and being influenced by worldwide natural gas fundamentals. The large arbitrage opportunity between the National Balancing Point (NBP) and Henry Hub, which was present throughout the first half of this decade, has been closed. As taking liquefaction capacity on a tolling basis is no longer in the money, are the next wave of projects being developed at risk of being delayed or deferred?

Shale Gas Focus Leads to Decline in Rockies Natural Gas Production

August 27, 2019

In 1969, the US government detonated an underground nuclear device in the Piceance Basin in Colorado to fracture a tight gas reservoir. While this initial effort was unsuccessful, oil and gas hydraulic fracturing techniques would later improve dramatically, leading to production growth in the Rockies during the 2000s, peaking in 2010 at nearly 11 billion cubic feet per day (Bcf/d). However, due to better economics in this decade, the oil and gas industry has switched to fracturing shale gas plays located outside the Rockies region, the net result being a decline in Rockies tight-gas production. Long-term potential does remain for Rockies natural gas, albeit at higher cost levels.

Lower Pricing to Reduce Production Growth in Western Canada Condensate

August 22, 2019

Western Canada condensate (C5+) production in 2018 from upstream, plant and fractionation sources totaled an estimated 360 thousand barrels per day (M bbl/d). It is projected to increase by approximately 1.1% between 2018 and 2030, reflecting a marginal increase in domestic growth brought on by increased drilling in liquids-rich gas plays. Remaining demand growth is expected to be satisfied from higher imports brought on by diluent requirements for heavy oil transportation.

Gas to Methanol Economics – US Gulf Coast versus Western Canada

August 20, 2019

On July 19, 2019, Methanex announced it was taking final investment decision on its 1.8 million metric tonnes per annum (MTPA) brownfield expansion of the Geismar 3 facility in Louisiana. It expects to begin operations in the later part of 2022 with capital cost of 1.3–1.4 billion United States dollars (B USD) or 775 USD per tonne (USD/t). Because a major cost input for methanol production is natural gas, one might ask why Methanex would choose the US Gulf Coast as opposed to Western Canada, where gas prices have been half those of Henry Hub over the past 2 years.

What is the Size of North America Natural Gas Resources?

August 12, 2019

Solomon has estimated dry natural gas resources and economics for major plays in the US Lower 48 and Western Canada. The analysis shows North America has at least 1,150 Tcf of dry gas with full-cycle cost1 below 4 United States dollars per thousand cubic feet (USD/Mcf) in major basins where most drilling occurs.

1 Solomon’s Full-Cycle Cost includes: Producer Return of 15% before tax, Finding and Development, General and Administrative Expenses, Royalties & Production Taxes, Operating Cost, Liquids Uplift, and a basis differential to Henry Hub.

How Long Could North American Dry Gas Resources Last?

August 12, 2019

A recent Solomon assessment found that North America has 970 trillion cubic feet (Tcf) of dry gas resources with full-cycle cost below 3 United States dollars per thousand cubic feet (USD/Mcf) and 1,150 Tcf of resources with full-cycle cost 4 USD/Mcf. How long will these resources last?

What Factors Affect Full-Cycle Cost of Western Canada Gas the Most?

August 8, 2019

The full-cycle cost of gas is comprised of a producer return of 15% before tax, finding and development (F&D) costs, general and administrative (G&A) expenses, royalties & production taxes, operating cost, liquids uplift, and a basis differential to Henry Hub. These factors are affected by gas and natural gas liquids (NGL) prices, as well as the CAD/USD exchange rate for Canadian gas. What factors would affect the full-cycle cost of Western Canadian gas the most?

Ontario Nuclear Refurbishment Could Increase Demand for Western Canada Gas

August 1, 2019

Potential exists for increased TC Energy Mainline pipeline flows resulting from Ontario’s plan to refurbish 8,000 MW of nuclear capacity at the Bruce and Darlington sites during the 2019–2032 time period. However, potential Western Canada production growth will depend on the ability of Western Canadian producers to capture increases in natural gas demand resulting from nuclear capacity going offline.

Outlook for North American Coal-Fired Generation

July 26, 2019

Over the last decade, programs at both the federal and state/provincial levels to reduce NOx, SOx, and carbon emissions have targeted existing coal capacity. Uncertainties with respect to long-term carbon policies have dried up investment in coal-fired projects as natural gas pricing and the cost of new renewable capacity have fallen, resulting in increased utilization and capacity growth for gas-fired and renewable power generation.

Will the US Gas Rig Count Continue to Grow?

July 24, 2019

Solomon forecasts the gas rig count based on the number of wells that are projected to be drilled in each major basin and play. The number of wells that are forecasted are based on allocating gas demand to the basin with the lowest full cycle cost of gas. For the 2019–2050 time period, these basins will be the Marcellus, Utica, Haynesville, and Eagle Ford. These basins currently represent around 40% of all wells drilled in the US.

LNG Exports, Oil Sands to Drive Future Demand for Western Canada Gas

July 18, 2019

Western Canada gas is used locally, particularly for oil sands production, and is exported from the area to Canadian and US markets using a number of pipelines. Western Canada gas demand will grow slowly, primarily due to competition with lower-cost gas produced in the US. However, after 2024, Western Canada gas demand will start to grow due to LNG exports. Another factor behind the future growth of gas demand is oil sands production, which is expected to increase after 2021–2022, when new oil pipeline capacity will become available.

What is the Goldilocks Level for Alberta Government Curtailments?

July 16, 2019

As the Alberta government’s oil curtailment program meets its commitment to take delivery of 4,000 rail cars to move incremental oil volumes, finding the Goldilocks level, or 20 United States dollars per barrel (USD/bbl) for the West Texas Intermediate (WTI)-Western Canada Select (WCS) differential, will become more important to ensure economic rail and maximum royalty conditions.

Haynesville Production Growth: What Should We Expect?

July 11, 2019

Haynesville production peaked in 2011–2012 and then dropped nearly by 40%. Approximately two years ago, Haynesville production started growing again, reaching a record 11 Bcf/d. Haynesville is a dry gas play and producers do not receive any liquids uplift. So what has caused this newfound production growth?

US Tight Oil Production Growth Triggers Rise in Gas Flaring

July 4, 2019

As illustrated in the chart, natural gas flaring in the US, particularly from tight oil production in the Permian basin (Permian) and Bakken play (Bakken), led to increased greenhouse gas (GHG) emissions. Although some efforts are under way to reduce such flaring, the growth in US tight oil production means flaring will likely remain an ongoing concern.

Tight Oil Drilling to Boost US “Free” Gas Production through 2030

July 3, 2019

US raw associated gas production will reach 27 billion cubic feet per day (Bcf/d) in 2030, up from 16 Bcf/d in 2018. Associated gas will become a very significant contributor to US natural gas production, mostly due to growth from tight oil basins, such as the Eagle Ford and Bakken plays.

Alberta Abandoned Wells: Over 10.5B CAD (and Growing) in Liability

June 17, 2019

Alberta faces a liability not only from maturing wells, but wells, pipelines, and facilities that have been abandoned by producers. This liability will grow in the next few years as more wells reach their economic limit.

Alberta has over 70,000 wells that need to be properly abandoned, including more than 3,000 wells designated by the Alberta Energy Regulator (AER) as orphan wells. In addition, other well sites, pipelines, and facilities in the province also need to be properly reclaimed. These unabandoned wells, pipelines, and facilities have created more than10.5 billion Canadian dollars (B CAD) in financial liability for the oil and gas industry. This liability will grow as a significant number of gas and coalbed methane (CBM) wells drilled before 2008 approach their economic limit.

Oil and Gas Reserves Life: Should We Expect Industry Growth in the Next Few Years?

June 12, 2019

Before the shale gas and tight oil boom, proved reserves and the average reserves life index were critical indicators of a company’s potential as a top producer. Conventional oil and gas required producers to be involved in significant exploration activities because of the limited supply pool of hydrocarbons. Producers could not increase production without these pools, and reserves had to be booked according to regulatory requirements.

Over the past 5–10 years, however, wells have become significantly more productive as producers pursue unconventional oil and gas, and undeveloped resources can be quite sufficient. As long as a company is developing shale gas or oil, they most likely will have sufficient resources and undeveloped reserves to pursue their business plans.

Will New Well Productivity Continue to Grow Indefinitely?

June 4, 2019

In recent years, we have observed a significant increase in new average well productivity in most major producing basins in North America. Will this trend continue, or will we see some decline of well productivity due to maturity of the basins?

The Solomon analysis from our Strategic Energy Advisory topic reports shows that in most producing basins, new well IPs will continue to increase, albeit at a slower rate, and then begin to flatten. This growth of IPs will lead to further reduction of full-cycle cost of oil and gas exploration and production. For example, Western Canada gas IP will grow slowly in the next 10 years. Average IP in some basins will start to decline before 2030 as low-cost areas are fully exploited, making these basins less competitive.

What Can Be Done to Stop British Columbia Ethane Rejection?

May 30, 2019

Ethane is used primarily as a feedstock for the production of ethylene, which is the basic building block of many petrochemical derivative products. It is also used to meet fuel and solvent requirements. In many parts of the world, ethane infrastructure does not exist, and ethane is often left in natural gas streams. Where ethane is recovered and utilized in the petrochemical industry (e.g., North America), it usually becomes the largest component of NGL supply and demand. Western Canada has typically recovered most ethane at straddle plants located on the export points to the east (Empress) and southwest (Cochrane). Some ethane is recovered at field-level plants; however, with an oversupply of ethane, field recoveries have been minimized.

What Can be Done with the Excess Butane in Western Canada?

May 23, 2019

Over the past year, butane prices have dropped significantly from around 65% of Edmonton Mixed Sweet (EMS) crude oil in early 2018 to about 5% in early 2019 due to oversupply and decrease in demand. Butane supply is expected to continue to increase as more producers are targeting economically attractive liquid-rich gas plays such as the Duvernay and Montney to benefit from high condensate prices (95–100% of EMS). In terms of demand, butanes are commonly used as fuel or refrigerants. Major demand drivers in Western Canada include petrochemicals feedstock, oil sands Steam Assisted Gravity Drainage (SAGD) as a solvent, and fuel additives in refineries. Butane is also commonly used as a fuel source, aerosol propellant, or a refrigerant (replacing Freon). 

How Many Wells Will Be Drilled in Western Canada Through 2030?

May 22, 2019

Well connections in Western Canada peaked at more than 18,000 in 2006, 14 times more than Solomon’s estimate for 1,300 wells in 2019. Average initial productivity in 2006 was 180 thousand cubic feet per day (Mcf/d); however, most wells had initial productivity below 100 Mcf/d. Low productivity required a very significant number of wells to be drilled to satisfy demand requirements at gas prices above 7.5 Canadian dollars per gigajoule (CAD/GJ).

The shift of producers in this decade to high-productivity horizontal well drilling resulted in gas prices plummeting and well connections declining significantly, while overall production grew with relative ease. Since 2012, most of the wells drilled in Western Canada have been horizontal, and account for 95% of well connections. Around 61% of Western Canada gas wells in 2019 will be drilled in the Montney or Duvernay plays; that share is expected to grow to 79% in 2030. 

Should a Montney Gas Producer Develop LNG or Just Buy Devon Oil Sands Asset?

May 16, 2019

Producers holding reserves in the Western Canadian Montney play have been searching for monetization solutions since last year’s open season for the Alliance Pipeline expansion capacity fell flat. LNG liquefaction presents a potentially large gas demand market with Henry Hub plus 15% pricing for Western Canada producers. However, would a more direct monetization route be to purchase a producing oil sand asset with ~100 million cubic feet per day (MMcf/d) of gas demand for in situ steam production instead?

Why Marcellus Drilling Activity Increased in 2018 While Montney Activity Declined

May 14, 2019

Drilling activity in the Appalachian basin, particularly in the Marcellus shale play, has increased significantly in 2018 compared to drilling that took place in 2017. A total of 1,066 gas wells were drilled in the Marcellus in 2018, a 59% increase from 670 wells drilled in 2017. Most of these wells were drilled in NE Pennsylvania, producing dry gas that does not require significant processing.

Is There a Public-Private Partnership Solution for West Coast LNG?

April 30, 2019

The Western Canadian natural gas industry is facing unforgiving competition from burgeoning US Lower 48 supply. Due to its relative location to market and existing infrastructure, production growth in Marcellus shale gas and associated shale oil has displaced Canadian gas supply traditionally exported to the US Midwest and Northeast markets. Small-scale solutions within the Western Canadian Sedimentary Basin are being explored to increased intra-basin demand. However, LNG remains the way to replace Bcf/d level market demand that has been lost.

Application of Nanotechnology in the Oil and Gas Industry

April 26, 2019

Since the late 1980s, countless technological advancements in many industries have been attributed to the application of nanotechnology. Nanotechnology is a multidisciplinary field that involves the manipulation of matter at the nanoscale level (1 – 100  10-9m). The unique physical and chemical properties of the resultant nanomaterials allow nanotechnology to serve as an advance platform to provide solutions to complex problems. In the wake of rising challenges facing the oil and gas industry, properties such as large surface area, high aspect ratio, mechanical strength, and high chemical reactivity have the ability—through the application of nanotechnology—to provide durable, less risky, and cost-effective alternative solutions to overcome technical and environmental issues associated with various oil and gas activities.

Will Permian Have Sufficient Pipeline Capacity?

April 25, 2019

Growing Permian production and tight pipeline capacity saw Midland-WTI spreads widen in 2018. Permian production rose from 0.4 million barrels per day (MM bbl/d) in 2010 to 2.05MM bbl/d in 2017. However, in 2018, production did not increase as quickly as previous years due to infrastructure constraints (i.e., oil pipelines, associated gas processing, NGL and gas pipeline infrastructure, and water infrastructure for fracking operations, etc.).

Moving forward, Solomon expects continued expansion of oil pipeline capacity to exceed production; however, the ability of refining capability to handle light barrels has started to reach its limits, shifting the bottleneck toward very large crude carrier (VLCC) export capabilities.

Will Permian Oil Production Continue to Grow?

April 18, 2019

Permian crude oil and lease condensate production in December 2018/January 2019 reached 4 million barrels per day (4MM bbl/d) and 13 billion cubic feet per day (13 Bcf/d) of gas. But will this trend continue until 2030? Does Permian have enough economically viable resources to ensure production growth? Solomon analysis confirms that Permian full-cycle cost will remain the lowest among United States Lower 48 tight oil basins, and lower than other tight oil basins such as Bakken and Eagle Ford. Significant resources at relatively low cost will lead to production growth in the next few years.

Why Do US Refineries Need Canadian Heavy Oil?

April 18, 2019

Refining capabilities to handle light barrels is nearing existing designed capacity limits, shifting light barrels to export markets. Near-term export bottlenecks will be solved with the completion of an additional 2 to 3 Very Large Crude Carrier (VLCC) export loading facilities. Economics and cost of upgrades to increase refinery capacity of light barrels require long-term planning and investment. Current assets supporting the imports of heavy oil continue to remain an economic alternative to satisfy refinery input diets.

Canadian East Coast Oil Production Summary

April 11, 2019

There are four producing regions offshore Newfoundland (Hibernia, White Rose, Terra Nova, and Hebron).

Overall offshore Newfoundland oil production averaged 230M bbl/d up from 220M bbl/d in 2017. Hebron production offset declining production of White Rose, Terra Nova, and Hibernia.

Canadian Oil Sands Production Forecast

April 9, 2019

After posting an 8.1% per year growth rate from 2010 to 2018, Solomon forecasts Alberta oil sands growth to slow with the completing of new large-scale mining projects. Solomon now forecasts an average annual growth rate of 2.9% (from 2.9MM bbl/d in 2018 to 4.2MM bbl/d in 2030). This represents nearly 80% of total Canadian oil production in 2030.

Will Gulf of Mexico Production Continue to Grow After 2019?

April 4, 2019

Oil production in the Gulf of Mexico (GoM) Deepwater grew to 1.4 thousand barrels per day (M bbl/d) in 2018 from 1.2M bbl/d in 2015. But will it continue to grow in the future? The Gulf of Mexico Deepwater oil development requires significant capital and lead time for exploration and development drilling, construction, and installation of production facilities and pipelines. However, the size of the resource and the production capability of the wells have the potential to make the projects economical. Although high, the capital cost of GoM Deepwater is 14 United States dollars per barrel (USD/bbl) and higher, the operating cost for GoM Deepwater is only 5.27 USD/bbl compared with around 9 USD/bbl in Permian basin. Solomon estimates that Gulf of Mexico Deepwater production will be only 8% of total North American Oil Production in 2030, down from 10% in 2019.

What are the NGL Resources in Western Canada?

April 2, 2019

Natural Gas Liquids (NGL) are components of natural gas separated from raw gas in form in liquids. They include ethane, propane, butane, pentane, and other components and used as an input for petrochemical industry, heating, or can be blended with gasoline into vehicle fuel. In Western Canada pentane plus is used for diluent for bitumen to transport it by pipeline. Western Canada currently produces 820 thousand barrels per day (M bbl/d) of NGL or 300 million barrels per year (MM bbl/yr). NGL production in Western Canada will grow to up to 1,000M bbl/d in 2030. But does Western Canada have sufficient NGL resources?

What is a Sustaining Cost of Oil Sands Projects in Western Canada?

March 24, 2019

Solomon analyzed sustaining cost of all major in-situ and mining oil sands projects. The analysis shows that sustaining cost for most projects was lower than average 2018 WCS price for in situ project and 2018 SCO price for mining project. However full-cycle cost of new projects is significantly higher. Full-cycle cost for new projects include full-cycle capital and cost of capital. New in situ projects need a bitumen price of 47 United States dollars per barrel (USD/bbl) to break even under today’s cost structure. Mining projects are able to cover their cash cost, overhead costs, and sustaining capital. New mine projects need an SCO price of 58 USD/bbl to break even.

Western Canadian Pipeline Capacities and Flow: Will We Have Enough Pipeline Capacity After 2021?

March 14, 2019

The figure shows total Western Canada oil supply, pipeline capacity, Alberta refinery demand, and potential pipeline expansions through 2030. In the near term, oil production in excess of demand and pipeline capacity will be transported to market by rail cars. Forecast observations:

  • With regulatory uncertainty and government intervention, oil sands producers have switched from business development strategy to an operations strategy. Therefore, Solomon believe producers will take a cautious wait-and-see approach and production will lag pipeline developments.
  • Enbridge flows are expected to increase until 2020 as Line 3 comes into service.
  • TransMountain Expansion completion in 2021 diverts rail and Enbridge Midwest directed flows toward West Coast/Asian markets.
  • In 2022, Keystone XL in service further erodes flows on Enbridge towards Cushing and Gulf Coast markets.
  • With incremental new pipe completed in 2022, rail shipments are no longer economic.

What are the Effective Oil and Gas Royalties in 2017–2018?

March 12, 2019

The figure shows effective royalty rates for the Western Canadian Sedimentary Basin for oil and gas. The last 4 years were based on the analysis of data from 30 publicly traded producers. Effective royalty rate for oil for 2017 was around 14% and for gas around 8%. Solomon expects that 2018 royalty rates will be similar.

Oil Sand CO2 Emissions: Will Alberta Exceed the Cap?

March 7, 2019

As part of the current Alberta New Democrat government’s climate change policy introduced in November 2015, emissions from oil sands development will be capped at a maximum of 100 metric tonnes per year (MT/yr). The figure shows CO2 emission forecast, based on Solomon’s forecast of oil sands production and emissions intensity. Solomon expects that as new technologies are more widely integrated (solvent injection, incremental infill wells), emissions intensity will decline. The hashed line illustrates a 1.2% per year increased efficiency in mining and in situ intensity and would effectively lower Solomon’s forecast for carbon emissions, which does not reflect any improvement in emissions intensity. The bottom line—Solomon expects that Alberta Legislative Emission cap will not be exceeded before 2030, which is good news for both producers and the environment.

How Break-Even Cost of Tight Oil and Shale Gas Would Change Over Time

March 5, 2019

Solomon developed a model to forecast full-cycle cost for individual basins and across large regions. This model includes all factors listed in the article. The figure presents full-cycle cost forecast for Bakken oil. Current average full-cycle cost for Bakken oil based on data from all wells drilled in Bakken in 2017–2018 is about 43 United States dollars (USD). This cost will decline due to improved well productivity. New pipeline infrastructure will also contribute to the cost decline. However, after 2028, the cost will grow due to the maturity of the basins.

E&P Company Cost Reductions – Cyclical or Structural?

July 1, 2017

When studying economic conditions for a given market, economists often consider whether determining factors are “cyclical” or “structural” in nature. A cyclical disturbance is thought of as a business cycle impact that will revert back toward previous levels over a short-term time horizon (months to years); costs rise and fall with the overall economy’s expansion/contraction cycle. Structural changes are thought to be longer-term to permanent. Examples illustrating a structural change entail regulatory changes (regulations reducing sub-prime lending on homebuilding) or disruptive technology (Ford assembly line innovation on horse whips).