- Today I'd like to talk about how we calculate hydrocarbons in place for conventional oil and gas reservoirs using the volumetric method. An outline of my talk is given as follows: In the first part I'll discuss how this calculation can be applied to a simple rock sample at reservoir conditions. I'll then extend that to the same calculation at surface conditions since this is the more typical approach used in the industry. With those two ideas in place, I'll then use them to calculate the fluids in place for oil and gas resorvoirs. I'll then discuss the issue of consistency between water saturation and porosity since this has an impact on the actual calculation. I'll finally follow up with a brief discussion on how we do this for geo-cellular models since that is the more typical approach when we calculate fluids in place for rather large reservoirs. Imagine we have a rock of volume V sub B. The rock is composed of grains and void space, and the latter is occupied by resorvoir fluids. The fraction of the void space to total rock volume is defined as the porosity and typically the porosity can be measured in the lab by weighing a dried rock sample and then saturating the rock with a fluid of known density and then weighing it again. And from the difference in the weights and the density of the fluid we can calculate the volume of the void space and therefore the porosity. Then the hydrocarbon pore volume of this rock sample at reservoir conditions is given in terms of its volume times its associated porosity times the fraction of the pore space that is occupied by the hydrocarbon. This fraction is referred to as its saturation and the usual approach is to use one minus the water saturation instead of the hydrocarbon saturation. Since oil and gas reservoirs occur at a variety of different temperatures and pressures we calculate the volumes at surface conditions which is a temperature of 60 degrees fahrenheit and a pressure of 14.7 PSI. Then equation one for the case of an oil reservoir is modified by incorporating a term called the oil formation volume factor. And this oil formation volume factor is simply the ratio of the oil volume at reservoir conditions to surface conditions and it reflects the fact that oil generally shrinks as we bring it from reservoir conditions, a higher pressure, to surface pressures. And this shrinkage is due to the evolution of the dissolved gas. The oil formation volume factor can range anywhere from close to one up to something like one point six. One is where we have very little dissolved gas in the oil and one point six could be for a volatile oil where we'd see a dramatic shrinkage on the order of about 40 percent of the oil volume at reservoir conditions to surface conditions. Equation two can also used to calculate the hydrocarbons in place for oil and gas reservoirs. In the next couple of slides I'll show an example of this for a simple anticlinal structure containing oil where I use average properties, specifically the water saturation and the porosity in the calculation. The volume of the reservoir is characterized by its area as delineated by the oil-water contact and its gross thickness. The gross thickness is usually obtained by measurements of true vertical thickness in a series of wells. If we assume average values for the water saturation and the porosity then the oil in place, in terms of stock tank barrels is given by equation three. The area of the reservoir is in acres and the coefficient at the beginning of the equation is simply the conversion factor from acres to stock tank barrels. The equation includes the average reservoir net thickness rather than the gross thickness, and the net thickness excludes from the calculation those non-producing parts of the reservoir that essentially are shale. If our reservoir contains gas then we use equation four to calculate the fluids in place and the only difference we have in this equation compared to what we use for oil are in the conversion factor from acreage to standard cubic feet and in the formation factor. The formation factor is now called the gas formation factor and typically is quite small and reflects the fact that gas at reservoir conditions, specifically pressure, occupies a much smaller volume than at surface conditions. Once we know the oil in place of the gas in place, if we know the PVT properties of the fluids, we can determine the volumes in place of the associated fluids. That is, for an oil reservoir we can determine the gas in place by just taking the initial GOR ratio times the calculated oil in place, and for a gas reservoir we take the initial condensate gas ratio times the determined gas in place. One thing that complicates the relatively straight foward calculation of the fluids in place is that there can be a variety of different definitions for the porosity. The one we've been talking about is the total porosity and that's obtained usually by taking a rock sample and heating it up to an elevated temperature to drive off all the water in the rock. Another porosity that's commonly used is the effective porosity and it is usually defined as the total porosity minus the volume of the clay-bound water. The point is that we need to use a consistent set of porosities and water saturations to correctly calculate the fluids in place and therefore if we use phi total we need to use the associated total water saturation and if we use phi effective we need to use the associated effective water saturation and we can't mix the two, otherwise we won't get the correct value for the hydrocarbons in place. If a geocellular model has been constructed for the field then it can be used to calculate the oil in place and it's then simply a running sum over the individual oil in place calculations for the cells in the model. Each cell can have its own water saturation, porosity, volume, etc. We also include in this calculation for each cell a term called the net-to gross. And the net-to gross is simply that fraction of the cell volume that is reservoir versus shale.