Volumetric Reserves Estimation

Abstract

An accurate estimation of oil and gas reserves is a key to the success of every field development, and this continues throughout the life of the field. There are several methods available for hydrocarbon reserves estimation and these are analogy, volumetric, decline analysis, material balance and reservoir simulation. The accuracy of any of these techniques depend solely on the type, quantity and quality of the geologic, geophysical, engineering, and economic data available plus the assumptions adopted for technical and commercial analysis. Also, the success of the reserve evaluation rely on the integrity, skill and judgment of the experienced professional evaluators. Thus, this chapter is basically dedicated for volumetric method of hydrocarbon reserve estimation which requires a limited amount of data. This chapter gives an understanding of the input parameters required and the factors affecting the volumetric reserves estimation. The step by step approach on how to calculate hydrocarbon reserves, bulk volume from Isopach map, condensate reserve calculations, an understanding of the deterministic and probabilities methods of reserves estimation are presented here with example cases.

Exercises

Ex 3.1

• I. State the methods available for reserves estimation and explain when each of the is used

• II. List and explain the factors affecting reserves estimate

• III. Why is STOIIP determined from material balance method different from volumetric method?

• IV. Give reasons while reserves estimation is often high with volumetric method

• V. The calculation of STOIIP from volumetric method involves several parameters, state these parameters and the sources where they can be obtained

• VI. What is the practical implication of taking cut-off in petrophysical data?

• VII. What is the factor used to covert acre-ft to stb?

• VIII. What is the implication of net-to-gross ratio in volumetric estimate of STOIIP?

Ex 3.2

The hydrocarbon contents of a reservoir were determined from the data of cumulative bulk volume (CBV) at the indicated depths on the table below.

Depth (ft)	CBV (ac-ft)	Depth (ft)	CBV (ac-ft)
9400	0.00	11,200	58866.34
9600	3159.46	11,400	64419.35
9800	11623.16	11,600	70282.13
10,000	23833.84	11,800	76.469.17
10,200	33547.92	12,000	82988.40
10,400	38822.03	12,200	89843.60
10,600	43697.74	12,400	97035.93
10,800	48568.69	12,600	104564.78
11,000	53597.63

The following petrophysical and PVT parameters apply: Gas-Oil contact (GOC) = 10,400 ftss; Oil-Water contact (OWC) = 12,200 ftss; oil formation volume factor = 1.3279 rb/stb; Gas expansion factor (E_i) = 185.1 scf/cuft; sand/shale factor (F) = 88%; porosity = 18%; connate water saturation = 13%.

• I. Indicate on a depth vs CBV plot, the depth at which the oil volume is acting

• II. Calculate the volume of free-gas initially in place (in MMMscf)

• III. Calculate the volume of the stock tank oil initially in place (in MMstb)

• IV. Calculate the gas cap size, m

• V. Find the centroid depth of the reservoir

Ex 3.3

A hydrocarbon reservoir is mapped out in area recorded at corresponding depths as given in the table.

Depth (ftss)	Top Area (acres)	Base Area (acres)
8800	0.000
9000	33.21
9300	91.31	0.00
9400	112.64	16.20
9500	125.06	32.40
9700	148.23	54.00
10,000	175.55	79.92
10,400	215.62	116.64
10,500	228.74	127.44
11,000	297.32	183.06

• I. Using numerical approximation method, determine (in Mac-ft) the cumulative bulk volume (CBV) down to the OWC

• II. Find the centroid depth of the reservoir

• III. Calculate the hydrocarbon pore volume in MMbbls down to the OWC for the following three sets of petrophysical data:

  • (a) All sand with porosity 21% and connate water saturation of 20%

  • (b) 50% productive limestone with porosity 17% and connate water saturation of 30% 50% non-productive

  • (c) 5/8 ^ths sand as above; 3/8^rds limestone as above

Additional Data:

Crest of top reservoir = 8800 ftss; crest of base of reservoir = 9400 ftss; OWC = 10,700 ftss; 1 acres = 7758.4 bbls.

Ex 3.4

Calculate the following with the data given in Table 3.8:

Table 3.8 Ugbomro gas field data

• I. The gas initially in place

• II. Gas in place after volumetric depletion to a pressure of 3540 psia

• III. Gas in place after volumetric depletion to abandonment pressure

• IV. Gas in place after water invasion at initial pressure

• V. Gas in place after water invasion at a pressure of 3540 psia

• VI. Gas in place after water invasion at a pressure of 555 psia

• VII. Gas produced by full water drive at initial pressure

• VIII. Recovery factor after full water drive at initial pressure

• IX. Gas produced by partial water drive at 3540 psia

• X. Recovery factor after partial water drive at 3540 psia

• XI. Gas produced by volumetric to abandonment pressure

• XII. Recovery factor at abandonment pressure

Ex 3.5

Use the Monte-Carlo techniques to calculate the porosity value from the set of data assuming a uniform probability of 0.89:

0.23, 0.21, 0.20, 0.24, 0.21, 0.205, 0.22, 0.21, 0.22, 0.22, 0.24, 0.235, 0.215, 0.21, 0.23, 0.21, 0.23, 0.23, 0.21, 0.20, 0.21, 0.23, 0.21, 0.20, 0.21, 0.21, 0.23, 0.20, 0.20, 0.21, 0.21, 0.20, 0.20, 0.21, 0.23, 0.23,

For:

• I. Fixed Value

• II. Uniform Distribution

• III. Triangular Distribution

• IV. Normal Distribution

• V. Log Normal Distribution

Ex 3.6

Calculate the gas reserve in a gas field of 2300 acres, with 40 ft. sand thickness, 23% porosity, 17% water saturation, initial pressure of 3200 psi and temperature of 200 °F. the composition of the gas and their weight fractions are as follows: 93.63% methane; 3.54% ethane; 1.46% propane; 0.38% isobutene, 0.36% pentane and 0.17% hexane plus.