Trends in Oil and Gas Production
Lesson Overview
The Trends Production Lesson consists of the following topics:
- Learning Objectives
- Environment: CCS Potential
- Environment: Produced Water Management
- Organization: Asset Team
- Optimize Production: Smart Wells and Fields
- Optimize Production: Offshore Communications
- Optimize Production: Multiple Completions
- Optimize Production: In-situ Technology
- US Marcellus Shale Gas
- US Haynesville Shale Gas
- Ultra Deepwater: Developments
- Ultra Deepwater: FPSO
Learn More About Trends in Oil and Gas Production
Click here to learn more about our Online Oil and Gas Training Certificate.
Environment
CCS Potential
One of the most common (shown in the picture) is injection of (CO2) into the production tubing through an annulus which makes the hydrocarbons in the tubing lighter, thus enabling them to flow freely to the surface.
Carbon capture and storage (CCS) is now considered a promising method of reducing carbon dioxide emissions into the atmosphere. CCS advocates want to capture CO2 from power plants, petrochemical plants and other industrial users and sequester it into depleted oil and gas fields, saline aquifers and unmineable coal seams.
The oil industry for decades has injected CO2 underground for EOR projects. Major existing CCS sequestration projects already underway are the:
- Sleipner project, off Norway,
- Weyburn project in Saskatchewan, and
- Salah project in Algeria.
Produced Water Management
One of the most controversial environmental areas for oil and gas Production Operations today is the handling, treatment and disposal of produced water.
Oil and gas production generates tens of billions of barrels of water annually along with the recovered hydrocarbons. Today, in addition to treating reservoir fluids primarily to remove water from the oil, a whole new set of facility investments and chemicals is needed to recover microscopic oil droplets suspended in the water.
Engineering estimates indicate that it takes 4–20 bbl of water to produce a barrel of oil in today’s unconventional reservoirs. This water needs to be cleaned so it can be recycled.
Treatment of produced water (adding to lifting costs) may become as important as the oil itself to allow other well site uses, such as:
- recycling back to the reservoir (as water or steam) to enhance production,
- hydraulic fracturing projects (especially in shale formations), or
- simply to prevent subsidence.
Organization – Asset Team
Today, the tendency in E&P is to organize into (multi-disciplinary) Asset Teams versus a traditional functional structure, as shown in the chart.
Here, the Asset Operations Manager would be responsible for all technical and commercial functions associated with improving performance of a particular field or asset, including: Geologists, Geophysicists, Petrophysical Advisor, Facilities and Reservoir Engineering and Land.
Each Asset Team could have a different type of leadership and team composition – depending on the planned projects. For example:
- CBM development has a huge problem with water disposal, and a facilities engineer could be in charge of that particular Asset Team.
- In enhancing an existing reservoir, it would make sense to have a geologist or reservoir engineer as the head of a team, to ensure integrity of the technical assumptions.
The advantage of having Asset Teams is dedication and focus on very clear goals, and the ability to handle an entire project from lease all the way through until production is established.
The disadvantage is that an engineer could have a limited career path as he/she moves from team to team, instead of handling more complex engineering problems in the specific discipline.
Production Optimization
Smart Wells and Fields
The ‘smart well’ term refers to wells that are completed with valves and/or chokes located downhole in the reservoir and tied to sensing equipment which can be operated from the surface (even remotely).
It is now possible to control multiple well functions at the surface with a push of a button, such as production flow rates, injection techniques, measuring and testing operations.
Smart well technology dramatically increases the overall production efficiency of the well. With sophisticated software and secure well site connectivity, real-time production or reservoir decisions can also be made.
Offshore Communications
BP now monitors its Gulf of Mexico operations through 24 hour/7 day-a-week live video feed to/from its onshore technology center based in Houston.
In Houston, a series of control rooms now manages BP’s operated offshore assets. The Houston staff responsible for the day-to-day operations of these offshore facilities include:
- operations management,
- production and operations engineers, and
- reservoir engineers.
The new technology brings the offshore operators and onshore technical teams together to allow BP to optimize how it produces assets in real-time. Joint teams can help anticipate potential problems and take corrective action. Service contractors can also be connected to the network, when needed.
This is a big improvement over the simple data feeds, sent via satellite, used by operators in the Gulf in the 70’s and 80’s.
Multiple Completions
Operators can now install multiple completions when the wellbore passes through multiple pay zones. The chart show this technology in application in a set of horizontal wells.
Each zone then can produce at a different pressure and flow rate.
Running multiple completions in a single wellbore is, by far, the most cost effective way to extract the most hydrocarbons with the least amount of effort and equipment. This method alleviates the need to drill multiple wells and run multiple strings of casing and production tubing.
In-situ Technology
In-situ operations are required where oil sand reservoirs are too deep to be mined economically. In general, in-situ techniques reduce the bitumen’s viscosity and force it to the surface, using conventional well bores.
In-situ projects can be designed to be smaller and more modular than mining, resulting in less labor. An EY study suggests that it is easier to manage the capital costs of these smaller in-situ projects. The in-situ process, however, recovers a much lower percentage of the in-place resources (only 45%).
Two techniques are used in in-situ operations.
- Cyclic steam stimulation (CSS) injects high-pressure steam into the deposit, where it fractures the sands and melts the bitumen. The steam soaks for up to 24 months, and the melted bitumen is pumped to the surface using the same well bore that was used for the steam.
- Steam-Assisted Gravity Drainage (SAGD) uses closely located horizontal well pairs, one for low-pressure steam injection, the second (lower well) for bitumen removal. As shown in the picture, the steam reduces the viscosity of the bitumen, allowing it to flow to the lower well, where the condensed steam and bitumen are brought to the surface by pumps.
In-situ developments are energy-intensive. The process can use as much as 2 cf of natural gas per barrel of oil sands production. Therefore, natural gas cost and availability can be a constraint.
Domestic Shale Oil and Gas
The Marcellus Shale
With advanced recovery technologies now becoming commercial, two major US gas shale plays are being developed – the Marcellus and the Haynesville.
The Marcellus shale runs from the southern tip of New York, through western Pennsylvania into the eastern half of Ohio and West Virginia, as indicated on the map.
The Marcellus shale is estimated to contain 168 trillion cubic feet of natural gas in place. Optimistic reserves could be as high as 516 trillion cubic feet. For reference, the US currently produces roughly 30 trillion cubic feet of gas a year.
Marcellus shale has natural gas at a depth of 6,000 feet and is cost-effective with horizontal drilling recovery techniques.
Technology exists to recover 50 trillion cubic feet of gas from the Marcellus. If even this level of recovery is realized, the Marcellus reservoir would be considered a Super Giant gas field.
The Haynesville Shale
The Haynesville formation is a layer of sedimentary rock more than 10,000 feet below the surface in northwestern Louisiana, southwestern Arkansas and eastern Texas, as shown on the map.
Several energy companies have begun work in the area to explore the shale formation and drill for natural gas.
Operators in the Haynesville shale believe it will become the largest gas field in the US and fourth largest in the world.
Estimates are that the Haynesville Shale holds at least 7.5 trillion cubic feet of natural gas and, optimistically, up to 20 trillion cubic feet.
By comparison, reported proved reserves in the Barnett Shale are just over 2 trillion cubic feet, which, until now, gives it the reputation of being the largest onshore natural gas field in the US.
Ultra Deepwater
Other new challenging areas for offshore production, where water depths exceed 1,500m (5,000 feet), are the African Coast, the northwest shelf of Australia and the US Gulf of Mexico.
As the graphic shows for the Gulf of Mexico, some developments are underway in almost 3,000 m (10,000 feet) of water. In fact, the new term developing for water depths greater than 3,000m (10,000 feet) is ultra-ultra deep.
This is the new arena for production technology. As one example, consider the riser which moves the oil or gas from the seabed to the surface platform. A riser for 250,000 BCD of production needs to be 18” in diameter and over two miles long. The weight of a two- mile steel riser could sink the platform. So, composite materials from the aircraft industry are being investigated to reduce weight.
The current production limit on water depth is 3,700 m (12,000) feet based on the weight of these new composite risers.
The FPSO
FPSO (Floating Production, Storage and Offloading) vessels are floating tank ships, used in offshore deepwater and ultra deepwater applications. They are designed to receive the oil or gas produced from the platforms, process it, and store it until the oil can be offloaded into arriving tankers. These FPO facilities can service many nearby platforms.
A true FPSO has the capability to carry out some preliminary forms of oil separation alleviating the need for such facilities to be located on the platform itself (saving crucial floor space).
FPSOs are particularly effective in remote locations. They eliminate the need to lay expensive long-distance seabed pipelines from the oil well to an onshore terminal.
They can also be used economically in smaller oil fields which will be exhausted in a few years and do not justify the expense of installing a fixed oil platform or pipeline. Once the field is depleted, the FPSO can be moved to a new location.
Related Resources:
What is the difference between Upstream and Downstream?
Drilling Wells for Oil and Gas and Offshore Drilling