# Exercise 14: Estimating HC Volumes

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1 Exercise 14: Estimating HC Volumes Objective Calculate a first-order estimate of the volume of oil that could be contained in the Alpha and Beta prospects using a simple reservoir volume formula and typical rock and fluid properties. Part 1: Gross Rock Volume A present-day structure map for the top of the target reservoir is shown in Figure 1. Both Alpha and Beta are fault-bounded anticlines. Based on geophysical evidence, the HC-water contact in Alpha is at a depth of 2600 m; in Beta it is at 1800 m. With this map, a reservoir thickness (isopach) map, and the dip of the fault plane, we can get a fairly accurate value for the gross rock volume of the reservoir (rock + fluid volumes). For our exercise, we will assume that Alpha and Beta are simple half-cones. We will also assume a constant reservoir thickness of 100 m. We can get the gross rock volume of the reservoir by calculating the volume of half-cone formed by the top of the reservoir down to the fluid contact and subtracting the volume of the half-cone formed by the base of the reservoir down to the fluid contact. 1

2 For gross rock volume, we can use the formula: V grv = ½ [ ⅓ π (r top ) 2 h top - ⅓ π (r base ) 2 h base ] or V grv = 1/6 π [ (r top ) 2 h top - (r base ) 2 h base ] 1 Estimate the gross rock volume at Alpha using these values: r top = 4.5 km r base = 3.9 km h top = 800 m = 0.8 km h base = 700 m = 0.7 km Use units of km 3 2 Estimate the gross rock volume at Beta using these values: r top = 4 km r base = 3.5 km h top = 800 m h base = 700 m Use units of km 3 Part 2: Reservoir Volume The gross rock volume contains both reservoir and non-reservoir layers. We use a parameter called Net-to-Gross (N/G) to express the percentage of the target interval that is truly reservoir quality (layers from which HCs can be can produced). The formula for reservoir volume is: V res = V grv * (N/G) 3 Estimate the reservoir volume at Alpha using a N/G of 35%. 4 Estimate the reservoir volume at Beta using a N/G of 30%. 2

3 Part 3: Pore Volume Reservoir volume can be partitioned into the volume of the solid grains and the volume of the space between the grains the pore volume. Porosity (φ) is the parameter that tells us what fraction of the reservoir volume is pore space where the fluids are located. The formula we use is: V pore = V res * φ 5 Estimate the pore volume at Alpha using a porosity of 25%. 6 Estimate the pore volume at Beta using a porosity of 22%. Record your result on Table 1 last page. Part 4: In-Place HCs If the target reservoir interval has been charged with HC, most but not all, of the pore space will contain oil or gas. Some of the pore space will contain residual water. Hydrocarbon saturation (S HC ) is a measure of how much of the available pore space is filled with HCs. The formula we use is: V in- place = V pore * S HC 7 Estimate the in-plase volume at Alpha using a hydrocarbon saturation of 80%. Record your result on Table 1. 3

4 8 Estimate the in-plase volume at Beta using a hydrocarbon saturation of 80%. Record your result on Table 1. LET'S ME OPTIMISTIC! We will assume that the reservoir is filled with oil down to the fluid contact - i.e., no free gas cap. Part 5: Converting to Barrels The unit of volume typically used for oil is millions of barrels (). We can use a simple conversion factor to go from volumes in km 3 to. (We could have done this conversion at any point after step 1). V = V km3 * Convert your estimate of oil in-place at Alpha to. Record your result on Table 1 last page. 10 Convert your estimate of oil in-place at Beta to. Record your result on Table 1 last page. 4

5 Part 6: Estimated Ultimate Recovery (EUR) Modern production techniques can only move a small portion of the in-place oil. The oil that is moved to the surface will change volume as it is brought up. This is due to the differences in temperature and pressure conditions in the reservoir compared to at the surface. We estimate the ultimate recovery (EUR) using values for the recovery efficiency (RE) and the formation volume factor (FVF) the correction for volume change. The volume change between the subsurface and the surface is sometimes called oil shrinkage. We use the formula: EUR = V in- place * RE * FVF 11 Calculate an EUR for Alpha assuming RE= 25% and FVF = Calculate an EUR for Beta assuming RE= 20% and FVF =.90. 5

6 Part 7: Risked Volumes The EUR you calculated in part 6 is an UNRISKED number it assumes that everything in the hydrocarbon system works favorably. However, the chance that everything works is not 100%. Typically experts will estimate the chance that each component of the hydrocarbon system (source, migration, reservoir, etc.) has worked. To keep things simple, we will assume that everything will work except possibly the fault seal. We believe that there is a 62% chance that the faults will seal so that oil will be trapped in Alpha and Beta. 13 To get a risked EUR, multiply your results from Part 6 by 0.62 the COS. When performing the economic analysis, we use the risked EUR. Think about it, if 6 times out of 10 the system works, you have to base your economics on this factor. If the economic minimum for this area is 100 MOEB, what would you recommend to management about drilling these two prospects? Alpha: Beta: 6

7 7

8 ESTIMATES Alpha Beta 1. Gross Rock Volume 2. Reservoir Volume 3. Pore Volume 4. In-Place Volume km 3 km 3 km 3 km 3 km 3 km 3 km 3 km 3 5. In-Place Barrels 6. EUR Unrisked 7. EUR Risked 8

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