Knowledge of formation fluids during exploration drilling helps operators mitigate investment risks during the life of a reservoir.

The need for good, representative reservoir fluid samples is critical to the effective design and operation of a deepwater development project. The decision to build and deploy production facilities exposes producers to as much as several billion dollars of investment risk, and a solid understanding of formation fluids right after discovery plays an essential part in mitigating that risk.
Formation fluid analysis provides data critical to predicting well and reservoir performance, surface and subsea facilities design and fluid quality assessment for determining market price. These data also can provide vital information on what hardware will be needed, including metallurgy for wells and production facilities, valve sizes and type, maximum flowline length and optimum diameters for subsea tiebacks.
Frequently overlooked, but no less important, is formation water sampling and analysis. Ultimately, most wells will produce some formation water, which tends to corrode and deposit scale on tubulars and processing facilities hardware. Additionally, in the event that seawater injection is planned to boost hydrocarbon recovery, it is necessary to ensure that mixing seawater and formation brines does not result in precipitate dropout - which causes pore plugging in the formation and tubulars - or increased reservoir souring (generation of hydrogen sulfide). The producing company gathers fluid samples from the discovery and appraisal wells. These invaluable samples can be stored and tested later, since it may be years before a facility is built, all wells are drilled and production begins.
Small samples yield ample data
While the impact of fluids on a project is large, the volume of reservoir fluid that can be collected in deepwater wells is relatively small, ranging from 250 cc to a maximum of a few gallons. Sample volume size is limited by the capacity of available openhole subsurface sampling tools, commonly referred to as formation test tools. These tools push a probe into the target rock formation and extract fluids into attached storage chambers for retrieval to the surface. This is considered a safe way to take samples because they are taken while the well is static; in other words, fluids are not allowed to flow to the surface.
Well testing in deepwater Gulf of Mexico wells (flowing exploration wells to the surface to get large fluid samples and test reservoir boundaries) is rarely performed because of high costs, gas flaring concerns and lack of storage capacity for the produced oil aboard exploration rigs.
However, the cost of obtaining fluid samples with formation test tools can be significant, on the order of US $200,000 to $1 million. Rig cost, a key component, can be as much as $400,000 per day for, say, a dynamically positioned drillship. Test tool rental and fluid transfer services incur additional expense.
Fluids important to business cycle
Reservoir fluid samples are collected during all exploration and production project phases, including abandonment. To better understand why fluids are collected so often, it is useful to consider the stages a project moves through in its business cycle. At each stage money is invested, even though the return on investment starts only in the final stages.
Prediscovery. The prediscovery stage typically takes 2 to 4 years. It involves seismic data acquisition, prospect identification based on that data, prospect acreage leasing, additional geologic and seismic studies to reduce risk and making the decision to drill an exploration well.
Exploration and appraisal. This phase runs 2 to 4 years and takes place after initial evaluation of seismic and geological data. Following exploration success, it consists of a discovery well and several subsequent appraisal wells for assessing reservoir volume and quality. This stage can cost several hundred million dollars, with some recent Gulf of Mexico exploration wells alone exceeding $100 million. Despite the high cost, these wells rarely are flowed to surface for reasons given above, and frequently are plugged and abandoned or suspended for future use after relevant samples and data have been extracted. These are highly expensive data collection exercises.
Another critical aspect of the exploration phase is obtaining the highest quality reservoir fluid samples possible using formation test tools. An inherent obstacle in formation test tool sampling is contamination by the filtrates in synthetic and oil-based drilling fluids commonly used to drill deepwater wells. Onsite evaluation of the collected fluid samples gives the operator the option to resample in the event contamination levels are deemed too high. The problem, however, is that the drilling fluid filtrates, being oil-based, interact with the naturally occurring hydrocarbons in the sample. This affects the phase behavior and thus the results of fluid property measurements and flow assurance testing. The lower the contamination level, the less the true fluids behavior is affected and the easier it is for models to correct the data. The high cost of extended rig time pales in comparison to the significant revenue loss that could result from poor facilities design based on skewed fluids data.
Field development. Running about 2 to 5 years, this stage is the costliest by far. For stand-alone fields, costs can run as high as several billion dollars. During development, the permanent production facility is designed, built and deployed; export oil and gas pipelines are laid; and some wells are drilled. First oil production follows. The cycle time from discovery to first oil is 5 to 8 years for most stand-alone developments. Oil companies strive to minimize this time since a huge capital investment is made before offsetting revenue begins.
Production and abandonment. During this stage, which lasts about 20 years, the remaining producing wells are drilled and targeted production volumes are achieved. This is the stage during which a return on the previous years of investment occurs.
Fluid sampling and analyses take place during all post-discovery stages. However, the impact of sampling on the project and its capital budget diminishes as the project moves forward, leaving fewer unspent dollars. Clearly, fluid sampling and analyses have the biggest impact during exploration and appraisal. At that time, the fluids can influence all aspects of the development plan, including facilities and well design, reserves estimates and project economics. During the field development stage, fluid data can impact the remaining drilling program, still a considerable project cost. Additionally, once a permanent facility has been deployed, cheaper and larger-volume separator samples can be taken for additional or confirmation fluids analysis. Finally, during production and abandonment, fluids sampling and analysis can influence future infill well programs, possible facility upgrades and even enhanced recovery processes, all of which represent additional capital spending.
Guidelines for fluid analysis
The blueprint for a comprehensive fluids program should address three key questions:
• What is the fluid behavior within the expected range of operating pressures and temperatures?
• Does this fluid have the potential for hydrate formation, asphaltene or wax precipitation (referred to as flow assurance analysis)?
• What is the market price of the discovered hydrocarbons, and how can they be accommodated in export and sales systems?
The first component is the most important and frequently referred to as reservoir fluid pressure-volume-temperature (PVT) analysis. PVT analysis is physical simulation of reservoir depletion and associated surface production. It allows reservoir engineers a window through which to view the future of their respective fluids, wells and facilities. PVT laboratories simulate, in a series of 3- to 5-day experiments, reservoir depletion that will occur during the life of the field. The most efficient plan for optimum commercial recovery can be developed when reservoir engineers know how the reservoir will behave.
Flow assurance testing is integral to all developments, but is especially critical on subsea tiebacks, where flowline blockage can shut down production. In subsea environments, flowline distances, pipe diameters and valve types and sizes are influenced by the PVT and flow assurance properties of the fluid (the predisposition of fluids to precipitate wax, asphaltenes, scale and hydrates).
The effects of 35°F (2°C) average seabed temperatures, as well as that of commingling several fluid types, also must be investigated. Preparations and interventions need to be made if the results of such analyses indicate dropout and precipitation will impede well fluid flow to its eventual destination. It is imperative to combine these data with PVT information so that future development can be planned. For example, when the viscosity of an oil limits production rates from reaching planned quotas, the decision may be made to drill more wells. In addition, facilities can be optimized. Separator configuration, number of stages and operating temperatures can alter surface yield ratios by as much as 30%. Such design is highly dependent on knowledge of fluid properties.
The impact on crude revenues
Knowing about the chemistry of the fluid is critical for determining what price the oil will fetch in the market. For example, refiners using Gulf of Mexico oil discount the price paid for crudes based on the amount of "impurities" contained in them. Oils can be discounted up to $1/bbl per percent sulfur in the dead oil. A decrease in API gravity can result in discounts of up to $0.15/bbl per degree API. Additional penalties for excess heavy metals content, crude acidity, residue content and methanol content also can apply. All can have a major impact on project economics.
What are the initial hydrocarbons in place for the field? What will the recovery factor be? How large is the reservoir compartment penetrated by this well? What quality of crude will be produced? What surface configuration will maximize the total fluid recovery and maximize revenue? What special equipment will be necessary to produce this field, and how will that impact project economics? Does infrastructure exist that can accommodate these fluids?
These questions and more can be answered, in part, by the chemical and physical properties of fluids measured in PVT studies. Of course, understanding of reservoir rock and geometry also is necessary. However, the resulting data give the engineer and management team the information needed to help make multibillion-dollar investment decisions and maximize the long-term return on that investment.

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