Predicting reservoir drive mechanism

Exploring for Oil and Gas Traps
Series	Treatise in Petroleum Geology
Part	Predicting the occurrence of oil and gas traps
Chapter	Predicting reservoir system quality and performance
Author	Dan J. Hartmann, Edward A. Beaumont
Link	Web page
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One can predict drive type by analyzing (1) the reservoir system of a prospect and (2) the production history characteristics of similar nearby reservoirs.

Predicting drive type

Reservoir analysis includes making cross sections, structural maps, and isopach maps. Analyzing nearby producing fields yields the best set of inferential data. This includes (1) making plots of historical oil, gas, condensate, and water production and pressure decline and (2) making cumulative production maps. When all available information has been assembled, find the drive type that best fits the prospective reservoir system. The table below summarizes typical characteristics of primary drive types.

Drive	Characteristics
Water	Quality of aquifer pore geometry comparable to reservoir pore geometry Aquifer volume at least 10 times greater than reservoir volume Flat to gradual production and pressure declines Gradually to rapidly increasing water production late in life of reservoir Early increasing water production from downdip wells GOR (gas–oil ratio) relatively constant High recovery factor (50% or more)
Gas expansion	Moderate drop in reservoir pressure Moderate production decline Water-free production (or relatively minor) GOR flat for first 50% of production, then increases GOR increases rapidly in structurally high wells Moderate recovery factor (typically 30%)
Solution gas	Rapid drop in reservoir pressure early in production history Exponential production decline Water-free production (or relatively minor) Increasing GOR early, decreasing later as gas is exhausted Low recovery factor (20% or less)
Rock drive	Unconsolidated reservoir such as sandstone, chalk, or diatomite Reservoir in overpressure section No decline while reservoir compacts, then rapid production decline
Gravity	Steeply dipping beds or vertical permeability greater than horizontal Fractured reservoir Low-viscosity oil (in general) Rapid production decline High recovery rate (75% or more), but often with low recovery volume

Production history characteristics for drives

Figure 1 shows oil reservoir production history characteristics for water, gas expansion, and gas solution drives. To predict reservoir drive type, if possible, plot the production history of nearby fields with analogous reservoir systems and compare with these graphs.

Figure 1 Modified. Copyright: Levorsen, 1954; courtesy W.H. Freeman and Co.

Recoveries of oil vs. gas reservoirs

The table below shows typical recovery rates for oil vs. gas reservoir systems for different reservoir drive mechanisms with mega and macro port type systems (John Farina, personal communication, 1998; . Recoveries would be lower for meso to micro port systems. Use this table to project the recoveries for your prospects.

Reservoir drive mechanism	Percent ultimate recovery
	Gas	Oil
Strong water	30–40	45–60
Partial water	40–50	30–45
Gas expansion	50–70	20–30
Solution gas	N/A	15–25
Rock	60–80	10–60
Gravity drainage	N/A	50–70

Recoveries for sandstone vs. carbonate reservoirs

The American Petroleum Institute conducted a study to determine recovery amounts and efficiencies for water vs. solution gas drives for sandstone and carbonate reservoirs, summarized in the table below (Arps, 1967). Use the table to project recoveries for your prospects.

Drive	Units	Sandstone			Carbonate
		Min.	Ave.	Max.	Min.	Ave.	Max.
Water	bbl/acre-ft	155	571	1,641	6	172	1,422
	m3/h-m	199	735	2,113	8	221	1,831
	% STOOIP	28	51	87	6	44	80
Solution gas	bbl/acre-ft	47	154	534	20	88	187
	m3/h-m	60	198	688	26	113	241
	% STOOIP	9	21	46	15	18	21

See also

• Reservoir system basics
• What is a reservoir system?
• Analyzing a reservoir system
• Defining flow units and containers
• Reservoir drive mechanisms

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