Oil and gas production is pushing the envelope both technically and geographically.
The year 2011 has been a year in which advances have taken place in terms of the innovative technologies and products being developed, refined, and used to extract more reserves from existing reservoirs around the world. They also are being applied in physical locations where field development and production activity are being introduced, employed, or considered.
Cleaner, more efficient
The attention of most operators this year has been focused on the refinement and application of cleaner and more efficient technological solutions to achieve IOR/EOR goals, as well as on more accurate downhole data to aid their efforts to predict and prevent production-hampering problems from occurring in the first place.
Brinker Technology’s Platelet Barrier Technology is a newly introduced rigless thru-wellhead workover solution. The company says its compact, easy-to-deploy technology can increase production more efficiently than traditional methods. In the time it would take to plan one rig workover, this technology is able to address integrity issues in more than 100 wells, restoring production and releasing limited rig resources for workovers or drilling new wells.
The technology was the result of some outstanding creative thinking, inspired by the human body’s response to cuts and wounds. It uses sealing particles known as platelets contained within a viscous carrier fluid that is pumped downhole through the wellhead to the leaksite. The operator can control the carrier fluid to ensure it is positioned at the leaksite, where it is extruded through the hole, with the platelets then gathering together to seal the leak. The entire process can be completed in less than three hours.
Chemical tracer technology
Tracer technology is another area that has seen significant advancement. On the Tyrihans field offshore Norway, Res-man’s chemical tracer technology was used to allow the operator to monitor production to determine if the entire lateral was contributing and if water was coning to points along the laterals.
Resman replaced sections of the predrilled liner with screen sections containing tracer elements, which lie dormant until triggered by the arrival of oil or water before dispensing unique chemical “fingerprints” into the flow-stream that can be detected in wellhead samples. This solution offered sufficient insight into the inflow distribution with zero operational risk and lower costs.
Stimulation technology also took a step forward this year with Baker Hughes introducing OptiPort. The technology combines ball-drop completions with annular fracturing, reducing well completion costs. Optiport contains fracture ports opened by a pressure-activated valve; fracture ports replace perforations in a typical well bore. Once the ports are open, fracture treatments are pumped down the well-bore coiled tubing (CT) annulus. Each zone is treated sequentially, starting at the bottom of the well. Subsequent zones are isolated by bottomhole assembly run on CT.
Seeing is believing
With today’s technology it is now possible to actually see downhole images, with recent advances enhancing the operator’s ability to diagnose downhole problems and conditions that significantly benefit decision-making. Downhole video images do not take the place of logging tools, but they do complement them.
These tools are used for complex wellbore problems such as physical damage or downhole debris and to view fluid entries of oil, gas, and water.
Such video imaging has real value: fishing aid video images can determine size, orientation, and location of fish or debris; they also can allow operators to make a go/no-go decision based on determination of success and risk. Fluid entry surveys can locate the entry point of oil, water, gas, or sand and view flow regimes such as slugging, bubbles, or emulsions, and mechanical inspection can identify and locate tubular restrictions caused by foreign objects, buckling, or partial collapse. Video cameras can visually inspect casing leaks from splits or leaking collars and inspect perforations to identify burring, irregular hole shapes, splits, or anything that would preclude the operation of ball-sealers.
The Expro Group HawkEye IV system, which can work in 125°C (257°F) and 10,000 psi conditions (there is also a high-pressure tool rated to 15,000 psi), can now acquire and store clear images at 30 frames per second and transmit over an electric line for real-time view or playback on the computer.
Conventional land wells and offshore wells with a dry wellhead have valves that provide operators with easy access to the B annulus to check the pressure and make any adjustments. This is not an option on subsea wells; so instruments that monitor and detect variations in pressure behind the casing string are invaluable.
At this year’s Offshore Technology Conference in Houston, Emerson Process Management launched the company’s new Roxar Downhole Wireless PT Sensor System – Annulus B, a product developed over several years as part of a joint industry project with Statoil.
The wireless PT Sensor System instrument attaches to the same cable as the reservoir monitoring gauges and can detect variations in pressure behind the casing string, monitoring the B annulus pressure and temperature without any degradation to the original barrier element consisting of the A casing system. It can be retrofitted to the monitoring system of current subsea systems. The unit also is based on an electronic wireless system, where the signals and power are transmitted using induction technology applying electromagnetism. The power is transferred from a section in the production tubing. All that is required during installation is a part on the casing that is run like a regular casing joint. The completion, with the receiver in the tubing, is run like any other regular completion.
Following a feasibility study in 2005, a development agreement in 2007 quickly saw the system reach a point this year where it has undergone final qualification testing, with further longevity testing to continue into 2012. Pulse power
Not all of the significant production advances have focused on downhole improvements.
New technology from Paradigm Flow Solutions offers an alternative to traditional remediation methods for removing blockages from subsea pipelines.
With challenging reservoir conditions playing a role as well as water depth, tieback distance, and temperature, the consequences of blockages can impact risers, flowlines , pipelines, umbilicals, pipeline end terminations, and manifolds. Blockages can prevent delivery of critical chemicals to subsea facilities, with wax, scale, asphaltene, or hydrates buildup all severely affecting production levels and curtailing revenues.
Remediation methods traditionally involve deploying a coiled tubing system from a rig into the pipeline or undertaking subsea interventions using an ROV or saturation divers.
Paradigm’s Pipe-Pulse solution was developed as a flow oscillation method for the nonintrusive removal of blockages and can work remotely to locate and remove blockages in long-distance pipework up to 48 km (30 miles) away. It is designed to be connected on the topside facili- ties of the host platform through either the pig launcher or the umbilical termination unit to clear blockages.
The unit delivers high energy and volume pressure pulses into the pipeline or subsea umbilical that eventually shift the blockage. The technology has been applied in the UK North Sea to clear chemical injection lines in a 13.7-km (8.3-mile) tieback.
In a 15-km (9.1-mile) flowline at Shell’s Gannet asset, the tool cleared a blockage that had persisted for 11 years.
The technology has even been used to clear stuck pigs inside a flowline on a deepwater field in the Gulf of Mexico (GoM).
Improved metallurgy, motors that can operate at higher downhole temperatures, more efficient pumps, and greater gas handling capability are all qualities that have helped electrical submersible pumps (ESPs) attain the capability to operate over extended ranges and at higher temperatures, encompassing almost all current production conditions.
There are now more than 80 subsea ESP systems installed worldwide, with the average run life in the North Sea, for example, approaching four years of operation.
The use of dual-ESP systems, where there are two installed in a well with one in operation and one on standby, has its advantages, including a longer run time. The well can continue to produce when a workover is planned while also allowing the workover to be carried out in conjunction with other work rather than having to mobilize a rig for a solitary pull.
Most attention is being focused on the evaluation of designs from a system point of view in the subsea deepwater environment – taking into account anything that could impact the performance and longevity of the production solution. With operators wanting more horsepower in the well to increase productivity as well as enhanced reliability, the development pace of ESPs is accelerating rapidly to try to match their ambitions.
Major milestones already have been achieved. In May, Baker Hughes was awarded a contract by Chevron for the deepwater Big Foot development in the GoM that will see the first deployment of ESP systems inside the well bore, placed at a true vertical depth of approximately 4,900 m (16,000 ft).
The ESP systems are scheduled for deployment in 2014, with the 1,200-hp dual systems to be among the highest horsepower in-well systems ever deployed offshore. They also will be deployed on dual bypass systems, allowing for reservoir access and the ability to switch between ESPs without intervention.
As for run-life, another Baker ESP offshore Brazil set a record earlier this year when it achieved more than 1,360 days of continuous operation in more than 1,350 m (4,430 ft) of water after coming online in mid-2007.
Floating LNG first
Some milestones achieved this year were a little bigger in terms of scale. Take Shell’s decision mid-2011 to move forward with the world’s first FLNG development. Its pioneering Prelude project offshore northwestern Australia will require billions of dollars of investment in what will be the largest offshore floating facility.
It is likely to be the first of several such units ordered within the next couple of years, as operators proceed with accessing and commercializing remote gas reserves stranded in frontier areas. Although Shell describes much of the technology on this first-ever FLNG unit as “groundbreaking,” most of it will in reality be of a more evolutionary nature, being adaptations of technologies applied already either in offshore floating production projects or onshore liquefaction.
All of the advances discussed here, and so many more than could be mentioned, can be put down to one thing very typical of the production sector of the oil and gas industry – the diligent application of, and appropriate investment in, science and technology. Very rarely is there a “Eureka-moment” – it is almost always a painstaking and diligent approach by dedicated engineers and specialists to enhance something that has often been around for years that makes the difference.