JIP "setting the gradient" for deepwater drilling

The push into the deeper waters of young, rapidly deposited, depositional basins around the world has forced the oil and gas industry to change its perspective on well engineering design.

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The push into the deeper waters of young, rapidly deposited, depositional basins around the world has forced the oil and gas industry to change its perspective on well engineering design. The close margins between fracture and pore pressure gradients in these basins are the primary culprit in prematurely reaching the limit of existing deepwater drilling technologies.

In the past, drilling engineers simply have accepted the fact that the seawater column was a necessary evil, and engineering designs revolved around that fact. Technology to take away the effects of the seawater hydrostatic column was not developed until recently.

Early August 1999 will mark the beginning of a new era in deepwater drilling technologies. A joint industry project (JIP), consisting of four operators, four drilling contractors, and one engineering service company, revealed a first look at its contribution to the riserless drilling concept - subSea mudLift drilling (SMD).

The concept, conceptualized in the 1960s, uses a dual gradient drilling (DGD) approach. It was considered impossible in its time. Activity closer to shore was financially viable, and the push to what was then deeper water consisted of building a bigger and better drilling barge. Activity in what we today call ultra-deepwater was beyond the scope of reason. The concept allows for extended casing depths, eliminating intermediate casing strings required with conventional drilling techniques. Two more important benefits are a bigger production hole and enhanced well control features.

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Dual gradient drilling techniques allow for bigger production holes by essentially eliminating the water column and moving the rig to the seafloor.
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The current design is based on integration of blow out preventer, return line concepts, and existing marine riser. The riser is filled with seawater to equalize internal pressure with the seawater hydrostatic pressure outside of the riser. The riser also serves as a guide for drillstring tubulars into the wellbore, and support for the mud lines and umbilicals.

The invention of rotating pressure control equipment was one of the first "baby steps" for riserless drilling. SMD could be considered the second. The final steps for riserless drilling will be eliminating the riser altogether, and increasing reliability of seafloor "working" components. A support structure for mud return lines and umbilicals will be required, but should not be too difficult to design. The learning curve in these earlier steps should also yield improvements in the subsea pumping, monitoring, and control equipment. The next step for this design will be the use of a remote, stand alone riser, and a self-supporting riser. This step will lend to the use of subsea wellhead templates with flexible, retractable return lines moved from wellhead to wellhead, as required, and the mud lift system central to all of them.

The concept, as designed and presented now, has no minimum operational water depth. Economic advantages of a DGD rig do start to be realized around 4,000 ft water depth. Geologic and directional drilling questions have to be considered. If geologic formation pressures and operational pump pressures are close, a DGD system may be the best option.

Well control issues become more simplified with a dual gradient approach. The decision to shut in the well can be made quicker, before gas has a chance to substantially expand and enter the riser. Since the riser is essentially not readily available to the wellbore in normal operation, this is not a concern. The traditional method of monitoring well influx is primarily surface visual monitoring at the pits and bell nipple. This is highly susceptible to human error, especially on heaving rigs. The SMD system allows constant pressure monitoring on the well, both flowing and static. This gives drillers a tremendous advantage to detect, evaluate, and act on a possible well influx situation.

When the decision is made to initiate kick circulation procedures, the SMD system requires the monitoring of drill pipe and subsea mud pump pressures, the build of appropriate kill-weight mud, and employment of the "driller's method" of circulating out the kick fluid. It could be said that the SMD system allows the system to be always "on choke" or dynamically shut in - an important advantage over conventional systems.

This is where confusion starts, and the re-education of drilling personnel begins. Standard procedures in the past required that the driller shut in the well, wait, evaluate, consult operator personnel, then weight up the mud and kill the well. A SMD system gives drillers the ability to shut in and start killing the well as soon as kill weight mud can be built.

Balanced U-tube physics of a conventional drilling circulation system do not apply any more. Dual gradient systems cause an unbalanced U-tube scenario. Training drilling personnel to understand the physics behind this fundamental change, and how to deal with problems using this concept will take time. Educational schools developed by the JIP partners are already underway to train personnel.

The realization of this drilling concept forces the industry to ask itself the critical question: "When do we change the current way of thinking, and go completely riserless?" There is no argument with the fact that riser costs are a major contributor to total well costs in deepwater wells. The system, as designed now, retains the use of a riser (for the testing and prototype phases). The economics for running riser systems to 10,000 ft and deeper will continue to drive costs higher. This is in direct contrast to the "lowering drilling costs" requests operators have been giving to the industry for the past few years.

The argument to this is that technologies such as dual gradient drilling will allow bigger production holes, ultimately faster, and-yet to be seen-more production of in-place hydrocarbons. This scenario increases the cost "up-front" but allows recovery of these well costs in a shorter period of time with faster production rates. The net financial gain, however, is the same, or less. If total hydrocarbon recovery is enhanced tremendously, then there will be no question that retaining use of a riser is a viable alternative.

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