Technologies needed to meet deepwater business needs

Increased hydrostatic pressure impacts the design of subsea and pipeline installations (which in ultra-deepwater often is required to operate with internal pressure below hydrostatic conditions late in the field’s life).

Mooring analysis is integrated with the riser and structure motion simulations. Mooring systems for 10,000 ft of water are expected to be synthetic rope and chain systems for ultra-deepwater developments, as they impose a smaller vertical mooring load on the in-field structure.

Considering this background information, we have organized the associated technology gaps for 10,000 ft of sea water (fsw) production systems into four groups:

• Fundamental knowledge or science

•Maximizing the production revenue stream (cash flow)

• Development capex

• Facility opex over the life of the field.

Fundamental knowledge

Fundamental knowledge of the environment, production fluid behavior, and processes are used to establish project design philosophies. When knowledge gaps exist in this science, conservative engineering approaches and assumptions are specified for the facility’s design.

Two examples where conservative specification is frequently applied today include deepwater flow assurance strategy and riser fatigue criteria.

Deepwater flow assurance strategy is often specified to completely avoid all hydrate or wax blockage formation. Most current developments use extensive (and expensive) insulation to preserve production thermal energy. This is critical during emergency shut-ins when no operational long-term hydrate prevention measures are possible (like flushing of the production system). Insulation sufficient to hold production temperature out of hydrate conditions for 10 hours (or more) is usually specified. Alternatively, some operators use even more expensive active heating systems to remediate any hydrates that may form.

Riser fatigue criteria is conservatively specified in today’s risers as:

•The ability to accurately predict the riser motion is limited. New techniques for analyzing the structure, its mooring, and the risers as an integrated unit are improving

•Vortex induced motion is becoming defined and better understood

•The material’s fatigue behavior in various riser configurations and (potentially) with sour production are not well known.

As fundamental knowledge increases, this conservative margin can be reduced or removed resulting in significant capex savings.

Another method for reducing the flow assurance conservative margin is to have a reliable, proven remediation method for flowline and well hydrate blockages. This enables one to produce a field with more “operational risk” than if there were no viable blockage recovery method other than replacing of the equipment or flowline.

An emerging flow assurance philosophy is one of “managing” the risk issue rather than its “total avoidance.” Hydrates, unless they agglomerate and adhere to pipe walls, are not a production problem. There are several examples of “cold slurry flows” occurring naturally in the field, and DeepStar has current projects evaluating this phenomena. Further, one new class of anti-agglomerate inhibitors encourages the formation of hydrates where they are manageable in the production stream. As experience and knowledge increase, more fields will be developed using a hydrate management strategy. Simplification of the flowlines and trees will result in capex savings, as thermal insulation would not be required.

Maximize revenue stream

Any field development gains the most economic benefit by maximizing its production revenue stream. Several considerations help accomplish this objective. For example, producing at the maximum reservoir drawdown pressure consistent with managing the reservoir’s production integrity delivers the shortest production field life. Methods include:

• Provide artificial lift. In 10,000 fsw, and with GORs in the 1,200-scf/bbl range, natural gas lifting of the production system does not occur until well up in the production riser to the surface. Much greater reservoir drawdown pressures may be accomplished with seafloor pumping

• Agood knowledge of the reservoir is required to manage maximum drawdown pressures. Sensors and predictive simulation tools aid the reservoir engineer in optimization of production rates and ultimate recovery factors. Reservoir knowledge sufficient for management and downhole maintenance optimization has been one of the significant differences between wet and dry tree production systems in years past.

Dry trees have historically been easier (and lower cost) to collect and act upon this vital information. However, with new permanently installed well and reservoir monitoring systems and lower cost wet tree intervention methods, this reservoir recovery difference between wet and dry tree production systems is expected to narrow.

Likewise, the production facility and all supporting systems need to be highly reliable. The production facilities need to be producing and not deferring production.

Capex issues

For general economics, any capex cost that can be deferred to incur reasonable opex increases at a later date in the project’s life cycle usually improves field economics. This is a well known principle and operator project teams routinely optimize the balance between capex and opex alternatives. Reduction of initial capital yields one of the largest field economic impacts.

Consider the economic groups for a DeepStar semisubmersible 10,000-fsw deepwater development capex distribution. Notice that:

• Drilling and completions represent 40% of the capex

• The moored in-field structure and topside is 31%

• Flowline and risers are 19%

• Subsea equipment represents 9%.

Keep these percentages in mind as we consider capex technology gaps and methods to improve field economics. Cost reductions in these largest percentage categories are usually the most fertile areas to save capex.

In the drilling area, we have considered several systems.

For example, use deepwater well construction methods like dual gradient drilling or monobore well methods when field qualified and cost effective. Recent DeepStar studies show further work is required to economically use these technologies and define their application niche.

Deepwater MODUs have many capabilities with associated high dayrates. Some vendor work is demonstrating that with optimized subsea equipment designs and ROV-based tooling, many completion tasks can be taken off a completion rig’s critical path. This reduction in rig critical path items results in a reduction of total rig time required to support completion operations. Candidate tasks include jumper installations, or tubing hanger plug removal, tree cap installation, control pod service, avoidance of running a completion riser. These tasks would be performed as a parallel rig activity or performed from a low cost workboat at another time.

In-field structures

The 10,000-fsw in-field structures may save capex with the following technologies. The cost of an in-field structure is directly proportional to the weight and size of the load it must support.

In 10,000 fsw, riser loads are significant, especially if PIP insulation systems are considered. These riser loads become so great, that few if any existing installation vessels would be capable of supporting such a riser deployment. Thus, single pipe risers with external insulation or riser systems made from alternative materials (like composites or a suitable high-strength fatigue resistant metal such as aluminum) become interesting alternatives, both from fatigue performance and an installation perspective.

Topside loads can be minimized by using new light-weight processing equipment. This process technology is applicable for any weight sensitive surface piercing structure (spar, semi, TLP).

Synthetic mooring lines significantly reduce the vertical mooring load and make mooring systems in 10,000 fsw feasible. These synthetic mooring systems are demonstrating a beneficial bi-modal performance. That is, the mooring line stretches as the moored vessel offsets under static environmental loads and then oscillates with a much stiffer spring rate about this first order offset location. The benefit is that risers do not experience as much second order fatigue loading due to reduced second order motions.

Some deepwater development configurations do not require extensive surface facility support. These developments can be supported with minimum facility structures (MFS).

Normally unmanned, these small structures provide for cost-effective operations and maintenance support, chemical injection, power and control distribution, pig launching, flowline pressure venting, etc. The MFS application niche increases with offset of the field from its hub host facility. The MFS may also support subsea processing systems, overcoming some of the concerns presently associated with an all-subsea production system.

Another alternative for deepwater production systems are dynamically positioned FPSOs such as Frontier Drilling’sSeillean,operating offshore Brazil for over four years, or Bluewater’s Munin,currently operating offshore China. DP FPSOs do not use permanent moorings, so their stationkeeping equipment is depreciated with the FPSO. This reduces cost as the 100% sunk cost of mooring for each field is not required. Since there are no mooring lines in the water, a much less congested subsea arrangement is possible. Further work to develop cost-effective gas handling systems will make this DP FPSO development alternative even more attractive. This system appears best suited short-life fields.

Flowlines and risers

Riser and flowlines linking the 10,000-fsw structures to subsea facilities are an area for innovation. Conventional steel application limits are approached with some riser configurations in these GoM water depths. Approaching these design limits suggests:

•Qualify new deepwater high-strength steel riser pipe (for sour service and fatigue resistant characteristics)

• Qualify single pipe risers featuring external integrated insulation and buoyancy. This effectively reduces the weight of steel in the riser that must be supported by the structure. Make this insulation/buoyancy system compatible with efficient riser installation operations

• Qualify new riser materials like composite tubular and light weight metals like aluminum alloys and titanium. These new synthetic and composite materials (which may be engineered neutrally buoyant) and more fatigue resistant metals should optimize 10,000-fsw production system designs

• These alternative riser designs need to be compatible with installation and maintenance operations using low-cost and readily available workboats. Great savings result if deepwater pipe-lay and construction vessels are not required to support riser or flowline installation operations

• Additional simulation and analysis procedures are required for the integrated design of the floating structure, mooring, and risers. As mentioned, synthetic mooring ropes have a beneficial impact upon the fatigue loadings applied to the risers

• New operating philosophies allowing subsea high integrity pressure protection systems (HIPPS) enable an equipment pressure rating spec break to occur. If the riser system in a 10,000-fsw development is downstream of a HIPPS installation, the risers only need to be designed for a predetermined working pressure and not the full shut-in pressure of the wells. This greatly reduces the required amount and cost of riser materials.

Subsea equipment

Subsea production equipment ranges from simple satellite tree tiebacks to the emerging full subsea production system with seafloor processing, pumping, and crude stabilization.

Clearly, processing the crude as close to the wellhead as possible minimizes downstream flow assurance problems. This subsea processing equipment must be simple, reliable, and capable of operating without intervention for long periods of time. Although the benefits of such systems are known, adoption and field utilization of this technology has been slow. Programs to vitalize this work and improve industry utilization by reducing its application risk are needed.

Reliable low-cost subsea intervention services simplify subsea production equipment arrangements. For example, ROVs or AUVs may be used to open or close infrequently operated valves, eliminating a remotely operated control point. Consideration of new field operating philosophies enabled by such service equipment allows the subsea equipment arrangement to be simplified, reduced in cost, and improved in reliability. A variety of vessels support subsea construction. Some of these vessels are expensive to use (large derrick barges and deepwater J-lay pipeline installation). As one considers the installation and maintenance of subsea equipment, the designs should be revised to make installation and service compatible with low cost, low capability support vessels.

Opex issues

Most opex costs for the 10,000-fsw DeepStar semi stand-alone production scenario are a small percentage of the total opex, except for the four largest categories which represent 86% of the total. These are:

• Oil transportation to market (46% of opex)

• Production processing and platform operating costs (17% of opex)

• Major workover of subsea wells (12% of opex)

• Operators insurance (11% of opex)

Clearly these higher opex cost areas, except for insurance, are where new technology should be most applicable in support of production system routine operations.

Oil transportation

Pipelines transport oil to market, and oil is charged as a tariff in the base case scenario. Should the crude be of a lower quality, then a substantial quality tariff is also imposed, as this production brings down the value of the total oil mix transported in the pipeline.

Shuttle tankers have the potential to reduce the cost of the oil transportation service. This requires the regular storage of crude within the field between shuttle tanker visits. This can be accomplished by using an FPSO as the in-field structure or a separate storage tanker may be permanently located within the field to routinely receive production.

Platform tariffs and operating costs directly relate to the facility’s function and the manning required for operating and maintaining the facility.

New lightweight process designs are becoming available and highly reliable. This type of equipment is being developed for subsea deployment, but it is also applicable to offshore unmanned structures as well. If it can operate subsea, then it should also be capable of unmanned operation in a topside installation as well. De-manning a surface facility greatly reduces the opex.

Little can be accomplished to reduce the operating tariffs for chemicals and utilities, facility depreciation, and maintenance costs that are components of this cost.

Subsea well workovers

Major workovers in subsea wells are expensive when performed from a MODU. The purpose for such workovers include:

• Repair of completion equipment failures

• Recompletion of the well to another production zone

• Sidetracking the well to other reservoir targets.

Good quality control of equipment manufacture helps minimize completion equipment failures. Simple downhole completion designs minimize the amount of equipment at risk of failure.

Recompletion of a well to a new zone can be minimized by performing complex multizone initial completions and/or by using smart well technology. The reliability of such equipment is improving and operators are expected to use more such “smart” equipment to avoid the opex cost of major workovers.

Where reservoirs are complex, significant additional reserves may be producible if the wellbore is moved to a new area within the reservoir. DeepStar’s economic model assumed a full MODU well sidetracking operation would be required. In many onshore wells, such bypassed reserves are produced through drainholes drilled through the production tubing without removing the well completion. This saves considerable cost in both completion equipment and services. However, to be truly successful in subsea wells, such operations need to be performed from the lowest cost vessel capable of supporting operations. Norway’s OG-21 initiative suggests coiled tubing drilling from support vessels may provide such services. A great deal of research is required before this becomes routine practice.

It is relatively easy to identify equipment and processes that will benefit deepwater production scenarios. The challenge is advancing these technologies to the “project ready” or “field qualified” status, where the early user risk is managed and acceptable to operators.

Acknowledgements

We appreciate the DeepStar Phase VI participant companies (Anadarko, BP, ChevronTexaco, ConocoPhillips, ENI/Agip, Kerr-McGee, Marathon, Petrobras, Shell, Total, and Unocal) for supporting the preparation and presentation of the findings in this paper.

References

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