Jan Buiting

Short biography Dr. Jan Buiting (March 2010)

• Doctorate in solid-state physics & mathematics
• Radboud University, Nijmegen, The Netherlands
• Eighteen years with Shell Exploration, working in operating companies in The Netherlands, Thailand, Brunei, the UK and Nigeria.
• Six years with Saudi Aramco: Reservoir Characterization Department; Geological Modeling Division;
  Part of the GIANT team, focusing on Ghawar-Arab-D
• Expertise in 3D seismic acquisition and processing; Quantitative interpretation; Inversion; rock and fluid physics; reservoir geophysics.
• Published over 200 internal and external reports and papers

Abstract 1
New technology Saturation Height Models in Arabian Carbonates

In Saudi Aramco it was recognized early on that it is necessary to deal with the particulars and idiosyncrasies of water saturation in carbonate oil reservoirs. Intricate problems such as upscaling, interfacial tensions, multi-modality and intra-pore wettability variations had to be addressed in a fundamental way in order to obtain reliable water saturations and permeabilities.

Oil and water saturations within a rock are mainly determined by the pore architecture and the capillarity caused by the fluid-rock interactions. Porosity and pore throat dimensions are measured in a laboratory via techniques such as mercury injection capillary pressure experiments. We represent those measurements in terms of Thomeer functions and parameters. However, these analyses are done on core plugs, which are tiny compared to the volumes of rock sampled by well logs or the size of a grid cell in a reservoir model. To translate the properties, measured on a micro scale, to these much larger dimensions, an upscaling step is required. Uscaling of saturation height functions is when desiring to honor and retain the information obtained from core descriptions is not an easy step.

An important effect, which had to be included, is the variation of the wettability throughout the pore systems due to changes in the free water levels over geological times. These variations are mainly caused by tectonic movements of the reservoirs. Varying free water levels have direct consequences on the wettability and thus the capillarity. Moreover, these effects influence the distribution of the residual oil accumulations, which have to be taken into account.

Of course it was essential to adapt the methodology so that it fully honors the multi modality of the carbonate pore system. Micro-pores have different capillarity and wettability characteristics compared to the macro-pore systems and influence recovery in different ways.

The final results of our efforts are more complex water saturation curves, still based on the Thomeer functionality, but embedding all the fundamental physical effects mentioned above. It has been successfully applied to many of our carbonate reservoirs.

One of the important consequences is that intrusion of liquids for large pieces of rock can happen at much lower capillary pressures and thus much closer to the free water levels in oil reservoirs, with encouraging consequences for the commerciality of the transition zones.

Abstract 2
Fully Upscaled Buiting-Thomeer Saturation Height Functions

Much of the oil in Saudi Arabia is stored in giant and super giant multi-reservoir fields. The Arab-D limestone is the most important of these and the most prolific. The large volumes, excellent porosity and high productivity of these reservoirs do not mask the fact that these carbonates have complex pore systems. The problems associated with heterogeneous carbonate reservoirs pose significant and longstanding modeling complications that are not yet fully addressed by the industry. One important difficulty is the accurate modeling of the substantial transition zones present above the free water levels. In our giant fields, these transition zones hold large amounts of oil and are important commercial objectives. Commerciality requires accurate assessment of saturations and rock properties. Standard J-function methods are inadequate to model the well log observed saturation height behavior in the transition zones. It is necessary to characterize and account for the sample variations and scale when modeling the saturation behavior of large rock volumes. The reservoir properties of geo-cells and well bores must be reconciled with the measurements on core plugs. The measurements performed on these tiny pieces of rock need to be upscaled in order to represent the reservoir bulk properties.

Upscaling of core plug scale, laboratory measured, porosimetry data and transport properties has been a general and persistent problem since the beginning of reservoir simulation. This critical step has been handled, over the years, using a wide variety of numerical computational schemes, approximations and empirical methods. In this paper, we take the different and very specific approach of upscaling the capillary pressure data for the Arab D limestone. We base the approach on the availability of a large amount of mercury injection data and statistical analysis thereof, obtained by fitting hundreds of individual core plugs to Thomeer functions.

For the Arab-D limestone, and similar carbonates, we derive a closed form analytic expression for the upscaled capillary pressure function, which has significant implications for improving transition zone hydrocarbon volume estimates for this important petroleum system. The analytic expression also offers major efficiencies compared to other methods for application by petroleum engineers, provided that the pore systems are adequately investigated and statistically characterized. A key result of the upscaled formalism is that reservoir cells, consisting of a large variation of pore systems, will start to fill with hydrocarbons much closer to the free water level than when using saturation height curves based on cell-averaged values. Therefore, transition zones for upscaled reservoir elements (and well log volumes) are thicker than calculations based on data from a single core plugs would indicate. The accurate upscaling of pore system architecture is a major step toward the full understanding of the fluid-rock interactions in our giant field transition zones and an industry technical milestone.

Abstract 3
Reservoir Fluid Physics – the remaining missing link once you have the pore system

The distribution of water saturation within an oil reservoir is of paramount importance for volumetrics and production alike. Pore architecture and interfacial interactions between oil, brine and rock are key contributors to saturation variations. Electrostatic forces are responsible for these interactions. They determine the interfacial tension between crudes and brines (σ) and the contact angle (θ) between the liquids’ interface and the surface of the rock. The resulting quantity σ∙cos(θ) is the effective capillary pressure resisting the buoyancy of the penetrating oil and strongly determines the ultimate amount of oil in the pores. In general, Knowledge on the exact nature of these physical quantities is limited, in particular for carbonate reservoirs. It is clear that these interfacial interactions are the result of intra-molecular interactions. These electrostatic forces are not yet fully understood, in particular for reservoir rocks. It will be inferred that overall the σ∙cos(θ) values for carbonate oil reservoirs could be substantially lower than for clastic reservoirs. All these conclusions affect the apparent wettability of the reservoirs, with possible far reaching consequences for reserves and production of our carbonate oil fields.

Materials from Jan Buiting
Jan’s Upscaling Paper

More materials will be posted on this page as they are made available