Workshop Helps Operators Understand Reservoir Fluids

(Tech Connections Column, August 2003, American Oil and Gas Reporter)

A workshop in Houston, co-sponsored by Core Laboratories and PTTC’s Texas Region, focused on key aspects of reservoir fluids. Understanding how those income-producing hydrocarbon fluids change and interact through the life of a reservoir is important. It is especially critical in newer reservoirs where equipment decisions are being made before or during drilling, but there are opportunities even in mature operations.

Speakers, including William “Bill” McCain, Dave Bergman of BP, Lloyd Brown of ConocoPhillips, and John Zumberge and Kevin Ferworn of GeoMark Research, discussed several aspects of hydrocarbon fluids. This was a unique opportunity for workshop experts and participants to learn from each other.

McCain noted how hydrocarbon fluid phase behavior influenced many decisions, including how reservoir fluids were sampled, the types and sizes of surface equipment, reserve calculations, plan of depletion, and applicable improved oil recovery methods. Phase behavior refers to how physically distinct parts of a hydrocarbon system change and interact with changes in pressure and temperature.

There are five basic types of reservoir fluids: black oil, volatile oil, retrograde gas, wet gas, and dry gas. From a practical engineering standpoint, initial gas-to-oil ratios help identify the type of reservoir fluid. Laboratory measurements of the differences include mole percent heptanes plus, and for black and volatile oil, the oil formation volume factor.

With gases, dry gas is the same on the surface as in the reservoir. For wet gas, recombined surface gas and condensate represent the gas in the reservoir. In retrograde reservoirs, recombined surface gas and condensate represent the gas in the reservoir, but not the total reservoir fluid, since retrograde condensate stays in the reservoir.

PVT properties are only as accurate as the sample analyzed. Bergman addressed contamination issues in wells drilled with oil-based mud (OBM). OBM filtrate becomes dissolved in the naturally occurring hydrocarbons, and affects chemical and physical properties analyzed in typical PVT and fluid testing. General effects include lowering saturation pressure, GOR, and formation volume factor. Density and viscosity could either be increased or decreased, depending on the OBM and reservoir fluid properties.

Density and viscosity differences can impact well bore calculations and lifting design. Saturation pressure differences can impact studies on compositional gradients, and either updip gas in oils or downdip oil in condensate reservoirs. Properly decontaminated fluids can also be useful in better understanding reservoir complexities, including connectivity. Understanding the chemical and physical makeup of the pure filtrate base is the first step in correcting contaminated oil properties, requiring mini PVT studies on the OBM. Equation-of-state modeling techniques that match the OBM and OBM-free reservoir fluid separately perform well for correcting laboratory measurements.

Brown defined flow assurance as a production operation that generated a reliable, manageable, and profitable flow of fluids from the reservoir to the sales point. Recognized as critical in deep water, flow assurance issues can also influence shallow shelf and onshore operations. The flow-assurance discipline requires integrating skills and knowledge from many disciplines, and including all of them in the value chain. The flow-assurance discipline drives a new perspective to reliable production operations. Its vision goes from reservoir to sales, and from concept design to operations.

Zumberge and Ferworn shared how, using geochemistry, one could learn about hydrocarbon fluids in a reservoir. Using geochemical concepts and crude oil samples, one can learn about depositional environment, thermal maturity, and geological ages of source rocks.

Oil samples are much more readily available than source rock, so why not make the most of them? Detailed comparison of different oil samples, often referred to as fingerprinting, can provide information about compartmentalization and continuity. This recognizes that oil quality is affected by source rock depositional environment and age, thermal maturity, biodegradation, and in situ mixing. Gas geochemical analyses provide information about biogenic versus thermogenic gas concentrations.

Pressure gradients from wireline formation tests can be directly converted to reservoir fluid densities. Using its global database of crude oils and seeps, GeoMark has developed correlations that help predict downhole PVT properties from reservoir fluid densities and geochemical parameters. Studies have shown that integrating geochemical groupings and parameters in traditional engineering correlations significantly improves predictive accuracy.

The symposium provided an interface between research scientists, geoscientists, engineers and financial planners, as well as 40-year veterans with four-year veterans. Deepwater operators spend $500 million-$1 billion before “first oil” is ever recovered. It is absolutely critical that they know their formation fluids and rocks the best they can. The symposium covered today’s “hot fluids topics,” from ground-level phase behavior to the latest research in geochemical property correlations. Today’s reservoir fluid analyst must truly focus his attention on “PVT and beyond."

Editors Note: Presentations have been posted on PTTC’s Texas regional Web site, www.energyconnect.com/pttc/ archive/6_03_reservoirfluids.htm.