OTC technical program underscores technological advances offshore

Final attendance at the 1997 conference-which saluted 50 years of offshore technological progress-was 43,394, conference officials said (OGJ, May 12, 1997, p. 22). The total was almost 7,000 more than in 1996.

• Multilateral Completion Schematic

• A converted semisubmersible, Nanhai Tiao Zhan, operates the subsea manifolds and houses the electrical generation and distibution equipment for powering the electrical submersible pumps in Amoco Orient Petroleum Co's Liuhua 11-1 field. The FPS can also drill and work wver wells, as well as install subsea equipment.

Among hundreds of significant technical presentations at the 29th Offshore Technology Conference (OTC) in Houston, key papers focused on the complexity of well bore design, floating production systems, and pipeline-pigging innovations.

Technical papers highlighted how companies can reduce costs, add operational efficiencies, and leverage technology to extract maximum results from capital they invest in global offshore projects.

In addition to technical presentations, Edward E. Horton and Amoco Corp. received OTC Distinguished Achievement awards. Horton, president and principal owner of Deep Oil Technology Inc., received the award for individuals for his work in advancing deepwater technology. He was instrumental in the development of the tension-leg platform (TLP).

Amoco received the award for companies, organizations, and institutions for its contribution to Liuhua field project, a joint effort of Amoco Orient Petroleum Co., China Offshore Oil Nanhai East Corp., and Kerr-McGee China Petroleum Ltd.

Slimhole drilling

Offshore use of slimhole drilling technologies can reduce costs in consumables, logistics, and service, according to T. Duhen and A. Sagot of the Society of Petroleum Engineers and Y. Kerbart of Forasol-Foramer.

Compared with conventional drilling, costs can be reduced by $4.5 million, or 46%, for a 3,000 m well drilled in 2,000 m of water.

The authors estimated that a deep offshore slimhole rig capable of drilling in 2,000 m of water can be built for $120-150 million, commanding a rate of $75,000-100,000/day. Conventional rigs, on the other hand, command day rates of $150,000.

The environmental impact is significantly reduced through use of slimhole operations. For instance, slimhole volumes and flow rates allow drilling without a waste pit.

Duhen said that onshore slimhole techniques can be utilized offshore with very few modifications.

Multilateral connectivity

A procedure for completing a multilateral junction within a preexisting well bore showed that mature fields also benefit from new technology (see schematic, p. 26).

The objective for this project was to drill and complete a dual-lateral well with commingled production. The difference between this procedure and others is in the installation of a cemented junction with re-entry, isolation, and connectivity capability.

The case history, presented by R.D. Jones, P. Lurie, and E. Hibber of BP Exploration Operating Co. Ltd. and P. Butler and A. Freeman of Halliburton Energy Services, detailed a successful step-by-step procedure for installing a multilateral juncture point.

The procedure involved the following steps:

• Run and set multilateral packer.
• Mill casing window.
• Drill 81/2-in. lateral.
• Retrieve solid whipstock.
• Run hollow whipstock.
• Run 7-in. lateral liner.
• Cement in two stages.
• Drill 6-in. open hole.
• Run 41/2-in. liner.
• Mill 45/8-in. pilot.
• Enlarge pilot hole to 61/16-in.
• Reestablish parent well bore.
• Complete upper well bore.
• Run through-tubing diverter in order to access lateral.

Well selection procedure

B.J. Batchelor and M.C. Moyer, Exxon Co. U.S.A., discussed how horizontal reentry wells can achieve production rates five times greater than those of typical wells.

Technological breakthroughs include implementation of medium-radius build rates in soft and unconsolidated formations, horizontal completions in reduced hole sizes, and use of casing whipstocks for sidetracking.

Two field prospects, the ST 54 G and West Delta 30, were compared according to geologic complexity and target geometries.

In order to achieve benefits from the learning curve, simpler directional wells were drilled first, progressing to more complex ones.

Existing well bores and geologic control eliminated the need for pilot holes in the ST 54 G prospect.

Limited geologic control and geometric limitations delayed the West Delta 30 program until last.

Well kick behavior

Insights into physical processes explaining well kick behavior were described by L.C. Schilhab of Sedco Forex and I. Cooper of Anadrill.

The presentation emphasized the effects of gas solubility in oil-based mud (OBM) and the possibility of entraining high volumes of gas within this fluid type.

Schilhab said gas dissolution in OBM may provide a mechanism to reduce the pressure rise during a shut-in. Under other circumstances, however, a pressure drop may also induce a secondary influx of gas.

Temperature profoundly affects solubility.

Schilhab estimated that a 1° C. change will increase the hydrostatic pressure by 116 psi in a typical high-temperature, high-pressure configuration.

The dynamic interaction between fluid loss, well bore compliance, solubility, and mud compressibility must be considered in estimating the gas migration rate.

Schilhab found that despite the complexity of gas migration, general rules may be applied.

For instance, gas concentrations greater than 10% will rise at approximately 100 fpm.

Floating production systems

Technical presentations at OTC indicated that floating production systems (FPSs) are now active in most of the world's areas.

FPSs offer cost-effective methods for developing deepwater or marginal fields. These systems include the use of TLPs and converted or new tankers for floating production, storage, and off- loading (FPSO) service, as well as semisubmersibles.

Sessions covered developments such as Shell Deepwater Development Inc.'s Mars TLP, Oryx Energy Co.'s Neptune spar in the Gulf of Mexico, Mobil Equatorial Guinea Inc.'s FPSO installation in Zafiro field, and Elf Congo's Nkossa FPSO off Africa.

Other floating systems covered at the conference included Den norske stats oljeselskap's (Statoil) Lufeng 22-1 development off China, Petrobras' deepwater fields off Brazil, and several new systems for the North Sea.

At the conference, Amoco Corp. received the OTC Distinguished Achievement Award for its Liuhua 11-1 oil field, the largest oil field found to date in the South China Sea.

A converted semisubmersible, Nanhai Tiao Zhan, installed in 1,000 ft of water, features two permanently moored floating production vessels and electric submersible pumps for artificial lift (see photo, p. 27).

To produce a viscous (88 cp), 19° gravity, low GOR oil from Captain field in the North Sea, Texaco chose a newbuild FPSO connected with flexible risers to a wellhead platform in 350 ft of water.

The fast-track U.K. North Sea project, described by S. Etebar, Texaco Ltd., came on stream in March 1997, a little more than 2 years after government approval (OGJ, Mar. 24, 1997, p. 30).

The field's seven initial extended-reach horizontal producing wells are each capable of producing 15,000-20,000 b/d of oil with electric submersible pumps.

A.J. Wolford, PLG Inc., S.R. Perryman, S.W. Gosch, and B. Stahl, Amoco Corp., and F.J. Deegan, Det Norske Veritas, analyzed the risks involved in using dual-casing risers compared with a single-casing riser for Amoco's proposed Marlin field TLP.

Amoco in 1999 plans to install the Marlin TLP on Gulf of Mexico Viosca Knoll Block 915 in 3,240 ft of water.

The dual-casing production risers would be capable of carrying full shut-in tubing pressure. But the analysis concluded that the upgrade to a permanent dual riser at $6.9 million, or a hybrid design in which a dual riser would be run during workovers totaling $8.4 million, would not be justified based on reduced risk.

Operators are also evaluating the possibility of composite risers. Offshore composites up to now have been used for gratings, piping, skids, tanks, etc.

F. Botros and J. Williams, Conoco Inc., and E. Coyle, DuPont, concluded that composites for riser applications have the highest potential for cost savings on a TLP. They found that replacing steel for production and drilling risers could reduce hull, deck, and tether cost by as much as 15-20%.

Their conclusions are based on a joint project of Conoco Inc., DuPont Advanced Materials System, and Kvaerner Group. The investigation evaluated the technical feasibility and benefits from composite materials for structural applications in deepwater platforms of a hypothetical tension-leg wellhead platform in 1,400 m of water in the North Sea.

Composites are usually more expensive than carbon steel on a per-unit weight basis. But because components are usually 50-70% lighter than steel, they are ideal for weight-sensitive structures such as TLPs, according to the study.

In another joint-industry project, D.D. Baldwin and N.L. Newhouse, Lincoln Composites, K.H. Lo, Shell Oil Products Co., and R.C. Burden, Hydril Co., described the early tests of composite risers for 3,000-5,000 ft of water.

The tests are being run on fiber-reinforced polymeric composites.

In addition to risers, composites also are scheduled for Statoil's Aasgard field to tie subsea wells to the floating production and offloading (FPSO) system (OGJ, Mar. 3, 1997, p. 32).

A.B. Hansen and B. Asdal, Compipe AS, and T. Meland and I.O. Grytal, Statoil, in another presentation said the material selected was a spoolable fiber-reinforced polymer with a thermoplastic liner.

They described the liner as acting as a chemical barrier, pressure seal, mandrel for winding the composite laminate, and leveler of potential stress concentration on the laminate; it provides for a smooth inner surface.

During 1997, the world's fourth LPG floating storage and offloading (FSO) system will start up. The project involves Chevron Nigeria Ltd.'s Escravos gas field off Nigeria. The first LPG FSO began operating for ARCO Indonesia in 1978.

The Escravos FSO is the first to include tandem mooring for cargo transfer. This required development of off- loading hoses capable of operating at -43° C., as described by S.P. Woehleke and H.T. Jones, Chevron Petroleum Technology Co., M. Zaffagnini, ITR SpA Oil & Marine, and G. Gallant, Dunlop Ltd. Oil & Marine.

Multiphase meters

Operators are starting to turn to multiphase meters for allocating production back to each subsea well. Some meters have been installed while others are still being tested.

In Brazil, Petrobras and Fluenta Inc. have agreed to evaluate the deployment of multiphase meters in deepwater.

E.F. Caetano, J.A.S.F. Pinheiro, and C.C. Moreira, Petrobras, and L. Farestvedt, Fluenta, described the progress of the testing on land and the deployment during 1997 of the test meter in the Albacora field at a depth of 960 ft.

Fluenta's meter consists of a dual-capacitance sensor set, a gamma-ray densitometer, one Venturi-type meter, one inductive sensor, and pressure and temperature sensors.

The authors described the measuring process as being in two stages.

The first stage occurs during the prevailing continuous oil phase in which the volumetric fractions are measured by a combination of the gamma-ray densitometer and the capacitance sensor.

If the water is the continuous phase, measurements are with the inductive sensor and gamma-ray densitometer.

Electric conductivity of the liquid determines if the continuous phase is water or oil. The Venturi-type meter measures the speed. Gas bubble speed is measured by the capacitance sensors using cross-correlation techniques.

A pipeline T, upstream of the meter, provides homogenation of the stream.

The first subsea Fluenta multiphase flow meter was installed by Amerada Hess UK Ltd. in the U.K. North Sea's Scott field in May 1995. As described by S.G. Slater, A.M. Paterson, and M.F. Marshall, Amerada Hess UK. Ltd., the meter experienced an electronic component failure early in its service and required new technology to solve its problems.

Amerada Hess installed an updated version of the meter in its South Scott field in 1997.

Statoil has ordered some multiphase meters. O. Okland, K. Kleppe, H. Berntsen, and S. Klemp, all of Statoil, reviewed the results from a number of field tests.

After testing various meters, Statoil awarded a contract to supply eight topside multiphase meters for the Gullfaks satellites and 18 subsea multiphase meters for Aasgard and Gullfaks satellites to Multi-Fluid Int. (MFI). Statoil expects another 10-20 meters to be ordered in 1998.

Statoil also is conducting a 1-year test of two subsea meters from MFI and Framo on the Gullfaks B platform. These may be installed subsea in 1998.

At Gullfaks B, another multiphase meter has been in service since November 1996 for allocating production from an extended-reach well.

A.R.W. Hall, T.S. Whitaker, and B.C. Millington, National Laboratory, Glasgow, noted that the multiphase meters currently commercial are Agar MPFM-310, Fluenta MPFM 1900 VI, Framo MFM, MFI full-range multiphase flowmeter, and Kongsberg MCF-351. Others are in various stages of development.

They describe the meters as using one of the following velocity measuring techniques:

• Mixing and differential pressure -Framo and Mixmeter.
• Positive displacement-Agar and ISA.
• Cross-correlation-Csiro, Haimo, and Kongsberg.
• Cross-correlation and differential pressure-MFI, Esmer, and Fluenta.

For phase fraction measurement, they classify the meters as follows:

• Microwave attenuation-Agar and MFI.
• Gamma-energy absorption-Fra- mo, Mixmeter, ISA, Csiro, and Haimo.
• Dielectric properties-Kongsberg, Esmer, and Fluenta.

They concluded that multiphase flowmeters can measure within ?10% over a wide range of flow but are hard-pressed to reach ?5% uncertainty over the full range of multiphase flows without additional expensive development.

Pigging design

B. Smith, GD Engineering, S. Blower, Brown & Root, and G. Ferguson of BP Exploration described the design of a multiple pig launcher for installation on the Machar subsea production manifold, 150 miles east of Aberdeen in 300 ft of water.

The manifold is part of BP's Eastern Trough Area Project and is linked to the central processing platform by a 22-mile subsea multiphase pipeline.

The authors said that the length of the line and resulting temperature drop from the 120° C. well temperature means wax deposition is a possibility.

The need to keep the line clear of wax led to the development of an innovative design for the subsea pig launcher to enable single line subsea pigging as part of the pipeline maintenance program.

Design considerations included launcher capacity, method of deployment and type of installation vessel, control philosophy, subsea connection to the pipeline, pig-launch mechanism, and pig drive fluid.

The final design solution consisted of, in part, a vertical pig launcher (three pigs), an ROV-operated release mechanism, a pig drive option (produced hydrocarbons from the manifold), an ROV control (API 17H tooling interfaces), high-pressure cap structure, and pressure test stand.

The manifold pipe lay was completed this spring; site integration testing of the complete structure is due for July 1997.

Pigging operations are set to begin in October 1998.

Welding, inspection

For installation of the Mars TLP's 18-in. oil and 14-in. gas export pipelines in the Gulf of Mexico, Shell Oil Products Co. investigated use of automatic welding and ultrasonic weld inspection (UT).

Results of the investigation and use were reported on by F. Kopp and G.G. Perkins of Shell Oil Products Co., B.S. Laing of CRC Evans, G. Prentice of Shaw Pipeline Services, S.P. Springmann of J. Ray McDermott, and D.M. Stevens of Babcock & Wilcox.

This was the first use of automatic welding on a deepwater J-lay. Shell specified ultrasonic inspection to maximize the probability of detecting significant weld defects, especially those with significant through-wall height.

Use of automatic welding and automated UT for J-lay resulted in cycle times that were better than expected and considerable savings to Shell and the pipelay contractor, the authors said.

This was true even after the significant cost of the upfront effort to develop procedures, train welders, and gain confidence in the UT inspection procedures.

In addition, the automated UT inspection system provided fast and reliable means of inspecting offshore welds. Further enhancements to the system, such as a two-dimensional representation of the weld cross-section with accurate through-wall location of all indications, have already been implemented on Shell's more recent offshore pipelay projects, and further improvements are being made.

Copyright 1997 Oil & Gas Journal. All Rights Reserved.