Offshore in depth

Back in the 1950s, the upstream industry moved into a water depth that could not be accommodated by merely installing a wooden- or steel bottom-supported platform to house a drilling rig. A bunch of Texans and Oklahomans were struggling with their offshore operations. Drilling from those bottom-supported platforms was time-consuming, as they had to erect the platform, install the rig, and drill the well. Then, they had to reverse the process to go to the next location.

Offshore rig development and its growth. An industry pioneer came up with a submersible design that didn’t have to be taken apart, to move locations. Hence, the mobile rig idea was born. The submersible could only operate in fairly shallow water, but it was time-saving and afforded the ability to drill more wells in a given time period.

Thus, the first mobile drilling unit to operate offshore the U.S. was a submersible rig built in 1952 and finished in 1953. It was used initially by Shell Oil in the Gulf of Mexico, offshore Louisiana. It could operate in approximately 40 ft of water. Its name: “Mr. Charlie.” Shell contracted that first rig and drilled a successful well right off the bat, then wanted two or three copies of the same rig. Thus, the offshore drilling contracting company was born.

Forty feet of water was as deep as the industry thought that it wanted to go—but there was potential out farther in deeper water. Thus, the concept and design floating unit came to be, with the first one being a triangularly-shaped vessel that was very stable, once on location, but awkward to tow. Eventually, the hull design was changed, so the legs and pontoons were parallel to each other, which made it a lot easier to tow with less tugs.

From all that, the semisubmersible drilling unit has grown into deeper water depths and much greater drilling depth capacities. Wouldn’t some of those pioneers, who built Mr. Charlie, be surprised.

Forward-thinking technology. What is the FWTS? The Floating Well Test System (FWTS) is dynamically positioned, providing a means to produce and store oil and gas in deep and ultra-deepwater. It also tests reservoir parameters for extended periods. The FWTS can capture all produced gas, resulting in no flaring, while also processing and storing output. The system also will offload sales oil and gas to transport vessels. Last, but not least, the FWTS can run,  disconnect, retrieve and move the riser to avoid hurricanes.

The primary objective of the FWTS is to obtain sufficient data to gain an understanding of the reservoir’s production capability, sustainability and fluid properties. A secondary objective is to produce a revenue stream from the sale of production.

The FWTS proves its value in several ways. First, it provides leaseholders with confidence in the reservoir, to make the right decision for their permanent facility. Second, it minimizes risk while maximizing development value to the owners. Last, the FWTS leasing cost will be comparable to the spread cost of a DP drillship operating in the deepwater GOM. Fortunately, this cost will be offset in part by oil and gas sales.

Further upside parameters include better understanding of characteristics of the production; reservoir pressure changes; better definition of the well’s productivity index/drawdown; and better definition of the reservoir’s drive.

The ability to get long-term data will result in a more cost-effective, economic development, along with a more efficient production facility.

It will provide a more definitive knowledge of the reservoir size, as well as a more definitive knowledge of well density. This ability will also assist in defining the most optimum, maximum, efficient production rate for longer well life, and maximum recovery per well with minimal intervention.

Clarification. In my inaugural column last month, some important wording was left out of the MODU discussion, resulting in significant confusion. The two tables of numbers actually referred only to units owned by the largest offshore contractors, including Atwood, Diamond Offshore, Ensco, Noble, Parker, Rowan and Transocean. The text about newbuilds should have said, “The 38 newbuilds that eventually come out of the construction shipyards will result in additional units joining these companies’ fleets.” Similarly, the sentence accompanying the second table should have said, “The existing rig fleet for these largest contractors is distributed among various locations around the world…..” We apologize for the confusion.