Challenges in the deep

Gas has been found in great quantities offshore East Africa. What will be the challenges around getting it to shore? Alex Hunt takes a look.

The East African coastline. Image from the GRID-Arendal Continental Shelf Programme.

Offshore East Africa is rapidly emerging as an exciting new frontier exploration play. Major gas discoveries, with volumes currently estimated to exceed 100 Tcf, have been made offshore Mozambique and Tanzania. An oil discovery has also been made offshore Kenya.

Further south, exploration licenses have been awarded offshore Madagascar and South Africa. Seismic data is currently being acquired and processed. In the far north, Somalia has been considering an offshore licensing round, although this has been delayed by the formation of a new government administration and negotiations with Kenya over the maritime border.

While no offshore field developments have as yet been sanctioned, a number of pre-FEED concept selection studies have been awarded. Final investment decisions for the first projects are likely to be made within the next three years. Almost all of the current discoveries are in water depths greater than 1000m. It is possible that both subsea facilities and floating production systems will be required.

However, the region has some very challenging characteristics that will require an integrated multi-disciplinary approach. Offshore production facilities will need to be designed for both installation and operation.

Metocean challenges

The seabed topography of East Africa is characterized by a very narrow continental shelf. To the south, it is less than 5km wide. However, to the north, it can extend out to about 50km. Water depths on the shelf are up to 400m.

This is followed by a steep drop to the ocean floor and water depths of more than 2000m. Slope gradients are typically up to 10%, although these can exceed 15% in places. The seabed then slopes more gently downwards to water depths in excess of 4000m.

The floor itself has a large number of ridges and sea mounts that are hundreds of meters in height. There is also a series of deep underwater canyons running out perpendicular to the shoreline that are hundreds of meters wide and kilometers long.

All of these obstacles, the very undulating terrain and steep slopes will pose significant challenges for identifying suitable routes and landfalls for future flowlines and pipelines.

In the Indian Ocean to the north of Madagascar, the surface current circulation is normally clockwise, although there is an equatorial counter-current in winter. However, to the south of Madagascar, the current changes direction and circulates counter-clockwise. Between Madagascar and the mainland, the Mozambique current flows from north to south and is magnified by the channeling effect between the two land masses.

There are also two monsoons. The north-east monsoon or kaskazi brings dry air in from the Persian Gulf from November to April and the warm, moist kusi monsoon blows in from the south-east from April to October. The slightly cooler kusi brings the heavier rains, from late March to early June. There is then a second rainy season in November and December. These may therefore place limitations on installation activities.

Because this is a frontier area, the oil and gas industry currently has limited operational experience and knowledge. The seabed bathymetry is now being surveyed and mapped. There is maritime information available on surface currents, wind speeds and directions.

However, more data is needed on the strengths and directions of currents through the water column. Long-term data gathering campaigns using acoustic doppler current profilers (ADCPs) will provide the information required for the design of risers and moorings for floating production systems and will also support the planning of optimized installation programs.

Typical seabed profile.

Dry gas reservoirs

Although oil has been discovered offshore Kenya, the major finds to date have been dry gas reservoirs offshore Mozambique and Tanzania. One of the development options being considered is ‘subsea to beach’ full wellstream transfer with no floating production systems. However, dry gas reservoirs are defined as having no hydrocarbon liquids present. They will contain formation water.

As these reservoirs are produced, pressures and temperatures within the production systems will fall. Water, initially present as vapor, will begin to condense. These systems will therefore need to operate, at least in part, in the multiphase region.

In addition, since water will be present, it is likely that liquid corrosion and hydrate inhibitors will need to be injected for transportation over relatively long distances. This will increase the volume of liquids in the production systems and push them further into the multiphase region.

Possible pipeline route with tie-in points for subsea pressure boosting.

Multiphase flow

As pressures and temperatures fall, the gas velocity increases. Although a production system with low liquid loading might start in the stratified flow regime, the effect of the increasing gas velocity will be to move it into stratified wavy flow and, eventually, into slug flow. Each of these flow regimes has a greater pressure drop per unit length, so pressure drops will increase as the fluid moves closer to shore.

With the pressures and temperatures decreasing, more liquids will condense. The presence of more liquids increases the likelihood of a change in flow regime, leading to increasing pressure drops. These in turn cause more liquids to condense. The situation therefore escalates.

When the fluids reach the base of the continental shelf, the production systems will need sufficient pressure for the fluids to be able to climb the slope and reach the shore. The back-pressure in the system will limit natural flow and reduce reservoir recovery unless some form of pressure boosting is provided.

Slugging has two main causes. Hydrodynamic slugging is governed by gas to liquid ratios and flow velocities. However, terrain-induced slugging is related to the seabed topography. The major undulations of the East African seabed will increase the probability of slug flow and high pressure drops. Pipeline routes will therefore need to be selected that minimize these undulations in order to reduce the impact of terrain-induced slugging and overall system pressure drops.

High pressure drops are also undesirable if sand or solids enter the production system. The increasing gas velocity may eventually exceed the erosional velocity and the particles may damage pipework. In addition, in low flow or no flow conditions, gravity becomes dominant. With insufficient gas velocity to carry liquids and solids, they will drain downhill and back into the production system.

In the worst cases, the system may become liquid locked or blocked and the reservoir pressure available on restart may not be large enough to clear these accumulations, leading to loss of production. Overall, although the shortest distance between two points may be a straight line, the most efficient route to minimize pressure drop and liquid or solid build-up may not be the shortest or straightest.

Managing liquids

In order to avoid production systems becoming liquid-locked and to offset the effects of pressure drop as reservoir pressures decline, one option is to retrofit some form of subsea pressure boosting. Two-phase gas-liquid separation and multiphase pumping or compression offer one alternative. However, as the volumes of produced water increase, this may simply move the problem from one location to another further downstream.

For short tie-back distances this may be manageable, but the optimum solution would be to reduce the inventories of water and solids. This would have the added advantage of debottlenecking processing facilities later in field lives, when water handling facilities may become capacity-constrained.

In order to achieve this, three-phase subsea separation and pumping with produced water and sand reinjection is required. While this is a mature technology in water depths less than 1000m, further development and qualification would be required for deeper water applications.

Pre-investment

Offshore East Africa, pipelines and flowlines are likely to require more complex seabed routings in order to avoid major obstacles and to minimize the impact of pressure drop. Subsea boosting facilities may then be retrofitted where and when required in order to maintain production and increase reservoir recovery. However, pre-investment should be made in spool pieces, tie-in points and spare umbilical hoses to simplify subsequent installation.

This will require a truly multi-disciplinary project approach to develop designs that are suitable for installation and operation, both initially as well as during possible retrofit modifications later in field life.

This article is based on a presentation made in October 2014 at the DNV GL Pipeline Day London 2014.

Alex Hunt is the founder of Woodview Technology Ltd., a consultancy specializing in the identification, development and implementation of emerging and new technologies for the oil and gas industry. With over 30 years’ experience, he has previously held positions with Texaco, Total and BG Group, developing technology strategies and establishing and managing portfolios of research and development projects. He also lectures on flow assurance, subsea issues, deep water technologies, emerging trends and technology needs.