Delta Stim completion service using Delta Stim sleeves and Swellpacker isolation systems. Completion is configured for ball shifting. (Figure courtesy of Halliburton)

Drilling a well carries a fixed cost that doesn’t change whether it’s a prolific producer or dry hole. And in frontier areas offshore and in harsh environments, that cost can be extraordinarily high. Just the day rate – the cost to “rent” a latest generation, deepwater drillship – recently has reached upwards of three quarters of a million dollars. And the expenses just start there. What ultimately determines whether all that money is a wise investment is ultimate recovery.

When oil was easy to find, low ultimate recovery factors were acceptable, and until recently it averaged less than 50 percent of known oil in place for most fields. Various technical hurdles make 100 percent recovery impossible in a practical and economic sense, but increasing the average ultimate recovery from fields worldwide from 45 percent to 55 percent, for example, would make a huge difference in energy supplies.

Another economic attraction to increasing recovery from existing fields is that producing fields already have associated infrastructure. Necessities such as production flowlines, monitoring and control systems, power, and other essential equipment are in place. Even offshore, where field development costs are orders of magnitude higher than land-based projects, the ability to “tie back” to an existing production infrastructure can significantly improve project economics.

The industry has always known this, but not until recently has production technology development really “taken off” and made possible greater expectations of ultimate recovery at reasonable cost. Of course production technology alone is not responsible for making increased recovery possible. Simultaneous advances in drilling technology (with horizontal and multi-lateral wells and steerable bits, to name only a few examples) and especially advances in seismic technology and geoscience have also made large contributions.

But ultimately hydrocarbons have to get from the formation to the surface through a well bore, and that’s where production technology comes in. E&P magazine has tracked this technology – along with exploration and drilling – since its predecessor began publishing in 1929. The magazine’s Special Meritorious Awards for Engineering Innovation, widely regarded as the most prestigious awards in the industry, have cited the “best of the best” in these categories. A look at some recent examples will give those with some knowledge of the industry an idea of how far production technology has come and give others a sense of what it takes to produce hydrocarbons in the modern era.

Completing horizontal, multi-zone well bores to enable accurate fracture placement

The era of drilling a vertical well bore to total depth, lining the well bore with casing, and then perforating the casing at the depth of a single hydrocarbon-producing formation or zone so it will flow into the casing and up through production tubing is long gone. Today, the goal is maximum reservoir contact with a single well bore. This can mean producing from multiple hydrocarbon zones. Here’s how one company uses two technical innovations to accurately “stimulate” multiple zones for increased production.

Halliburton’s Delta Stim completion service provides operators new options for completing horizontal multi-zone well bores to enable highly accurate placement of fractures, with minimal or no intervention. The service incorporates two tools – the Delta Stim sleeve and Swellpacker isolation system – to selectively access a variety of pay zones in a single wellbore with the option to close off one or more zones at a future date.

Based on reservoir conditions, isolation can be achieved with either the Swellpacker isolation system or the company’s Wizard III packer for an openhole completion. Multiple options are available for shifting the Delta Stim sleeves – a ball-drop system or mechanical/hydraulic shifting tool run on coiled tubing or jointed pipe.

The system’s Ball-Drop Procedure enables a totally interventionless completion. The sleeve to be shifted is determined by the size of the dropped ball. This allows the number of sleeves in one installation up to nine with 4 ½-in. casing and 11 with 5 ½-in. casing. Mechanical-Shift Procedure enables multiple open/close cycles to permit closing or opening one or more zones at a future date. With this procedure, the number of sleeves that can be run in a single string is virtually unlimited. Opening the sleeve permits flow through the ports in the sleeve in order to fracture the portion of the zone adjacent to the sleeve. After stimulation, clean-up is assisted by flowing all lower zones simultaneously. Once completed, the sleeve functions as a standard production device, allowing full wellbore access.

Hydrate inhibition

Offshore, a major production challenge is the formation of hydrates. Methane hydrates are ice-like crystalline minerals in which hydrocarbon and non-hydrocarbon gases are held within rigid cages of water molecules. At high pressures and low temperatures water forms a molecular trap for methane. The result is a white, flaky material that looks like ice. Methane hydrates can become a hazard by blocking pipelines and interfering with oilfield operations. But there are recently developed technical solutions. BJ Services, for example, has developed a technology to combat this problem.

In theory, methanol should be able to solve any hydrate problems. However, in practice, a surge of water or gas production or other changes in production pressure/temperature can overcome a thermodynamic product’s ability to melt hydrates. Increasing the methanol flow to match surges is typically impractical from a volume-pumping standpoint and can create environmental concerns in discharge water or pipelines or fire danger because of its flammability.

Glycol, another chemical with thermodynamic action on hydrates, is much more expensive than methanol but is not flammable. Typically, operators who use glycol also employ reclamation equipment, which takes up scarce space on an offshore platform. Another option is low-dose hydrate inhibitors (LDHIs), which use kinetic and/or anti-agglomerant chemistry to efficiently inhibit hydrate formation. They work at very low injection rates, requiring specialized pumps and plumbing. Their main disadvantage is that they cannot dissolve hydrates that form if production or environmental conditions change—for example, if production has to be shut in for several hours.

BJ’s Ice-Chek hydrate inhibitor blends compounds with thermodynamic, kinetic and anti-agglomerant chemistry. Its synergistic triple chemical action efficiently produces a “slow-to-fail” phenomena: It limits the rate of hydrate crystal growth, discourages accumulation of any crystals that do form, and melts them to avoid any problems. In the field, this “slow-to fail” functionality provides operators a much wider window to adjust chemical feed rates if needed to overcome unanticipated changes in well pressure/temperature.

These examples are only two of many specific challenges confronting the industry today. But any technology devised to meet these challenges does not work in isolation. The approach to production challenges that holds the most promise is not one technology but many, and it incorporates not just technology but also people and processes. This approach is called integrated operations.

Integrated operations

StatoilHydro, Norway’s state-owned operating company, is a world leader in the application of advanced technology to optimize hydrocarbon recovery. The company has set publicly stated goals for improvements in recovery rates in fields it operates. One way it intends to achieve them is with integrated operations. StatoilHydro has begun a program it calls TAIL Integrated Operations (IO). The program is designed to extend the life of mature fields now in the “tail” of the production curve. According to the company, IO will create value and extract otherwise noncommercial hydrocarbons by:
- Production optimization;
- Better well placement;
- Improved resource utilization;
- Improved regularity;
- More effective drilling operations; and
- Improved HES (Health, Safety, and Environmental) factors.

In StatoilHydro, Integrated Operations means collaboration across disciplines, assets, geographical boundaries, culture, and companies. Key points of the collaboration model for TAIL IO include:

- StatoilHydro, ABB, IBM, Aker Kvaerner and SKF have joined forces in a committing and collaborating R&D effort to develop new technology for more efficient operation of oil and gas fields.

- The objective is to develop technology, processes and knowledge to extend the lifetime of StatoilHydro’s oil and gas fields, and thus improve the recovery factor and be an enabler for:

-Improved HSE
-Improve production by 5%
-Reduce Costs by 30%

- The developed technology shall be demonstrated through an extensive use of pilots in StatoilHydro’s business units.

- Proven technology shall be commercialized and provided to the marked by the industry partners.

Smart wells, smart fields

Smart fields can be thought of as a subset of integrated operations. Smart fields (also called “digital oil fields” use of reservoir and production system models in a closed loop. Measurements can originate from sensors in smart wells, or involve simple surface measurements from conventional wells. Measurements can also originate from other sources such as 4-D (time-lapse) seismic sources.

Smart wells are a subset of smart fields. Smart well technology involves downhole measurement and control of wellbore and reservoir flow. Essentially this means the installation of downhole or subsea production measurement and control equipment that can be manipulated from the surface.

Another promising component of the smart field is Life of Field Seismic (LoFS), which BP pioneered with the world’s first permanent array in the Valhall field in 2003. BP uses LoFS data for most Valhall subsurface activities including base management and well work, well planning, depletion and water flood monitoring, and static and dynamic modeling. The technology also provides improved structural definition of the reservoir including improved fault definition, fault characterization, improved thickness mapping, and improved imaging beneath the “gas cloud.”

Shell is another smart-field pioneer. According to the company, its smart fields are providing both the knowledge and the control by integrating digital information technology with the latest drilling, seismic and reservoir monitoring techniques. Combined with the experience of geologists, engineers and others, smart fields can help increase the total amount of oil recovered from a field by 10% and gas recovery by 5%, while also boosting the rate of production.

The company says Champion West is its flagship smart fields project. Located 90 km off the coast of Brunei in the South China Sea, Shell says this is the first field to be “born smart.” For 30 years Champion West lay dormant, its rich oil reserves locked 2,000 to 4,000 m (around 6,500 to 13,000 ft.) beneath the seabed in a complex web of thin reservoirs deemed too expensive to develop. The company claims that Smart Fields technology and new drilling techniques have turned Champion West into one of the world’s most advanced oil and gas fields.

Sensors with fiber-optic cables relay digital information about temperature, pressure and other field conditions to control centers on land. This enables continuous monitoring of production, and engineers can make decisions quickly on how best to extract the maximum amount of oil, monitor its movement within the reservoir and instantly spot production problems. They can take action either to solve a problem or to increase production by better managing oil flow.