INTRODUCTION
The Tertiary Niger Delta (Akata-Agbada) Petroleum System (referred to as Niger Delta Petroleum System hereafter) was assessed as part of the World Energy Project of the Energy Resources Program of the U.S. Geological Survey. The quantities of oil, gas, and natural gas liquids that have the potential to be added to reserves within the next 30 years were considered. These volumes either reside in undiscovered fields whose sizes exceed the minimum-field-size cutoff value (1 million barrels of oil equivalent in this petroleum system), or occur as reserve growth of oil and gas fields already discovered (field growth).

Our assessment methodology for estimating the numbers and sizes of undiscovered fields (Charpentier and Klett, in prep) is sensitive to the homogeneity of each population being assessed. Therefore, the Niger Delta Petroleum System was divided into two assessment units—the Agbada "Deltaic" Reservoir Assessment Unit (hereafter referred to as Agbada Unit) and the Akata "Turbidite" Reservoir Assessment Unit (hereafter referred to as Akata Unit). This division was made based on the fact that the number and size distribution of hypothetical fields in the Akata Formation will be significantly different than in the Agbada Formation.

As a check on the Monte Carlo results, we evaluated the petroleum yield of the Niger Delta assuming an accumulation sediment thickness of 3.0 km (most oil reservoirs occur between 1,000 and 4,000 m depth, fig. 2, Chapter A). The sediment volume defined by discovered fields is about 300,000 km³. To date, the known volume of recoverable oil in both oil and gas fields is 34.5 BBO (calculated from data in Petroconsultants, 1996). Our calculated oil yield is 115,000 bbls/km³ of sediment. The yield increases to 165,000 BOE/km³ when 93.8 TCFG gas is included. These yields are two to three times the maximum recovery of 53,700 BOE/km³ given for delta systems in 1975 (based on Niger and Mississippi delta data; Klemme, 1975). In the last two decades, the recovery of the Niger Delta has increased dramatically over Klemme’s estimate. This increase is probably due not only to new discoveries, but to field growth as well.

Field Growth
The assessment for the undiscovered petroleum in the Agbada uses data from Petroconsultants (1996) to estimate size and volume of undiscovered fields. As of 1995, 481 oil fields greater than 1 MMBO and 93 gas fields greater than 6 BCFG were established in the Agbada Unit. The volume data were "grown"¹ for 30 years to account for the observation that estimates of recoverable quantities in fields increase over time. A summary of the grown data for the Agbada Unit is in the table below.
 

Exploration for Undiscovered Petroleum
We evaluated the exploration maturity of the assessment unit using a variety of indicators such as field density and plots of past discovery data. A total of 574 fields (481 oil and 93 gas fields) at least as large as one million BOE are reported by Petroconsultants (1996), resulting in an average field density of one field in every 210 km². Attanasi and Root (1993) calculated their "current" growth in delineated prospective area per wildcat well for Nigeria at 39 km²/well. Attanasi and Root’s value represents that area added to the "delineated prospective area" by each wildcat well drilled. Although the area:well ratio is relatively small, growth has remained relatively constant since the late 1960’s, indicating that there has been a constant increment in prospective area with each wildcat well drilled. Although the growth in delineated prospective area per wildcat well will have to decrease sometime in the future, it is not possible to determine exactly when the decrease will begin.

Next, we evaluated the discovery history of the basin (field size and petroleum volumes). Analysis of oil exploration trends (fig. 2) show that a consistent high rate of number of fields discovered per unit exploration effort has been maintained but that the oil fields are smaller in size (fig. 3 and fig. 4). This decrease is reflected in the overall decrease in the slope of the curve in Figure 3 and by comparing the median size of the first third of the fields discovered (60 MMB) to the second third discovered (22 MMB) to the third third discovered (23 MMB) (fig. 4). This analysis shows that although as many fields are being discovered as in the past, the discovery sizes have been smaller during the last two-thirds of the discovery history.

A similar analysis for gas fields (fig. 2, fig. 3, and fig. 5) shows exploration of gas fields is less mature than of oil fields. The curves generated by plotting cumulative oil fields versus cumulative number of new-field wildcat wells indicate that, per exploration unit, the number of oil fields being found in 1995 is not significantly different than that in 1952. In addition, the size of the gas fields is not systematically decreasing with exploration—a median size of 116 BCFG for the first third discovered, 58 BCFG for the second third, and 119 BCFG for the third third (fig. 5). We might expect that gas discoveries may be more prevalent in the future, especially with development of liquefied natural gas export facilities (Thomas, 1995).

Future exploration targets for potential on-shore and off-shore undiscovered petroleum within the Agbada Unit include:

1. Structural traps similar to those explored in the past,
2. Stratigraphic traps, and
3. Faulted, low-stand sandstones on the slope edge.

Assumptions for Assessing Undiscovered Petroleum
The following four assumptions were made for assessing the undiscovered petroleum in the Agbada Unit.

1. Major growth fault trends and structural trends within each depobelt are relatively evenly distributed across the assessment unit (Evamy and others, 1978, their Figure 10). Even though large, easily identified structures have been preferentially targeted, a few likely remain to be found based on the field sizes found recently (second largest oil field discovered in 1990 and the third largest gas field in 1989).
2. Undiscovered fields likely will include a greater percentage (and number) of smaller fields associated with stratigraphic traps that have been less attractive exploration targets in the past.
3. Undiscovered fields will have similar characteristics with respect to API, sulfur content, and producing depth. However, gas to oil ratios (GOR) in these fields probably will be greater than reported due to poor tracking of gas data to date. The natural gas liquids:gas ratio (NGL/gas) in undiscovered oil and gas fields likely is represented well by reported data.
4. The maturity of gas exploration is less than that of oil as gas has not been a significant exploration target in the past. This assumption is supported by the fact that 75% of gas produced in oil fields is currently flared.

The estimates for the number and size of oil fields were derived as follows:

1. Minimum number of fields assumes that the stratigraphic traps within the assessment unit are not as numerous as we would expect, and the minimum field size is the cutoff for this petroleum system (1 MMBO).

 
2. Median number of fields reflects our conclusion that slightly less than one-half the oil fields have been discovered (based on exploration maturity analysis), and their median size is about one-half that for the second third and third third discovered fields.

 
3. Maximum number of fields assumes that the stratigraphic traps are far more common than we anticipated.
 

1. Minimum number of fields assumes that the stratigraphic traps within the assessment unit are not as numerous as expected, and the minimum field size is the cutoff for this petroleum system (6 BCFG).

 
2. Median number of fields reflects our conclusion that about 1/3 of the gas fields have been discovered, and median size is about one-half that for third third discovered fields.

 
3. Maximum number of fields assumes that the stratigraphic traps are far better than we anticipated, and maximum volume allows for several large gas fields to be found.

The Akata Unit covers the entire Niger Delta Petroleum System, and is stratigraphically below the Agbada Unit where both formations exist (fig. 1). The area of the assessment unit is 300,000 km²—about equal size to the Mississippi Delta complex. About 56,000 km² of the unit is on land and 244,000 km² is in water. The Akata Assessment Unit is hypothetical and has no reported fields.

Analogs for Hypothetical Fields
Potential exists for significant discoveries in turbidite-related reservoirs in the Akata Formation. Reservoirs would be associated particularly with proximal turbidite "mounds," low-stand sands, and channel deposits. Marine shale of the Akata Formation serves as both source rock and seal. Exploration for turbidite-related reservoirs in the Akata Formation will be in the deeper water offshore (turbidite reservoirs of the Campos basin, Brazil are currently being developed in waters >2,000 m in depth; Guardado and others, 1990). Onshore Akata reservoirs in the deeper stratigraphic sections underlying current production will be generally at depths greater than 2,500 m on the flanks of the delta to over 5,500 m in the center of the delta complex (see fig. 8A in Chapter A).

The Niger delta currently has three large submarine fan systems that have been active since the Eocene. We assume that, at least during the Oligocene and Miocene, these fans would have been extensive and perhaps each fan is similar to that deposited during the Oligocene in the Campos basin. Therefore, the Plio-Pleistocene channel fill and Oligocene sheets of sand in the Campos basin were used as an analogue for the number of fields in this assessment unit. We assigned three "sweet spots" to the assessment unit and assumed a much lower density for the remaining area in the assessment unit.

The oil field sizes in the Campos reservoirs were considered less useful than the number of fields because source rocks for the Niger Delta and the Campos are very different (marine in the Niger Delta versus lacustrine in the Campos Basin). The charge assigned to the hypothetical reservoirs likely reflects this difference. Therefore, the Gulf Coast offshore data were used as the analog for the median size of fields in the Akata Unit.

Assessment of Undiscovered Petroleum in the Akata Assessment Unit
The following is the input for our assessment of undiscovered fields (see Appendix A):

The estimates for number and size of oil and gas fields were derived as follows:

1. Minimum number of fields assumes the Campos reservoirs were a poor analog, and the minimum oil and gas volume is the cutoff for this petroleum system (1 MMBO; 6BCFG).

 
2. Median number of fields reflects our assumption that the Campos is a reasonable analog for the turbidite complexes, and median size reflects our assumption that the Gulf of Mexico offshore data are a good analog for oil and gas field sizes.

 
3. Maximum number of fields assumes that the reservoirs and traps are more numerous than we anticipated, maximum oil field size assumes that the Campos basin is an analog for oil field sizes as well as number of fields, and maximum gas field size allows for several gas fields >3 TCFG to be found.

MATERIAL BALANCE CALCULATIONS FOR PETROLEUM IN THE AGBADA ASSESSMENT UNIT
Mass balance equations provided by Michael Lewan (written communication, 1999) where used to calculate a "ball-park" thickness of mature source rock in the delta required to account for the amounts of recoverable petroleum in the Agbada Assessment Unit. The calculations are based on a number of assumptions that are substantiated by data from the Niger Delta or other source rock studies. Regardless, the calculations are not intended to be a rigorous treatment of the data and are presented to test the feasibility of our estimates.

Assumptions:

1. Mature source rock (active pod occurs at depths great than 3 k (Ro = 0.08%; fig. 18, Chapter A).
2. Twenty-five per cent of oil expelled is lost as residual during secondary migration (based on a study of petroleum generated from the Albany Shale; Lewan and others, 1995).
3. Weight of naturally expelled oil is 5 times less than during Rock Eval pyrolysis (Lewan and others, 1995).

1. Mean TOC used = 2.6 wt % (3.0 wt% median for USGS proprietary data; 2.2 wt% average reported by Bustin, 1988; 2.3-2.5 wt%; Udo and Ekweozor, 1988).
2. Mean Hydrogen Index used = 180 mg HC/g TOC (181 median for USGS proprietary data; 90 average reported by Bustin, 1988; 232, Udo and others, 1988).
3. Mean source rock density used = 2.26 (assumes 5% porosity.
4. Mean API used = 35 (0.85 g/cm³) (55% of Niger delta oils have API gravity values between 30 and 40; Thomas, 1995).
5. Surface area of sediment in Agbada Assessment Unit at depths greater than 3 km ? 100,000 (from fig 8B, Chapter A).
6. Petroleum Resources for Assessment Unit 1(discovered + undiscovered) = 106 BBOE.⁴

1. Volume of resource (discovered + undiscovered) = 106 x 10⁹ bbl
2. Volume of oil lost as residue (25%) = 35 x 10⁹ bbl
3. Volume of oil expelled = 141 x 10⁹ bbl
4. Mass of oil expelled = (141 x 10⁹ bbl) x (.159 m³/bbl) = 2.24 x 10¹⁰ m³

= 2.24 x 10¹⁰ m³ x (0.85 g/cm³ x 10⁶ cm³/m³) = 1.91 x 10¹⁶ g
5. Mass of mature TOC = 1.91 x 10¹⁶ g/(((165 mg/g TOC)/5)/1000 mg/g) =

5.79 x 10¹⁷ g TOC.
6. Mass of mature source rock = (5.79 x 10¹⁷ g TOC)/(.026 g TOC/g rock) =

2.23 x 10¹⁹ g rock
7. Volume of mature source rock =

(2.23 x 10¹⁹ g rock)/((2.26 g/cm³) x (10⁶ cm³/m³) = 9.85 x 10¹² m³
8. Source rock thickness = 9.85 x 10¹² m³/(100,000 km² x 10⁶ m²/km²) = 99 m.

Our calculations indicate that a minimum of 100 m and no more than 300 m of mature source rock are required to account for the estimated recoverable resources of the Agbada Assessment Unit. These thicknesses can be accommodated reasonably either in the Agbada Formation where mature or easily in the mature upper Akata Formation.

²Included in the mean volume of NGL. [Back]

³Included in the mean volume of NGL. [Back]

⁴These resource estimates includes oil, gas, and NGL resources.  The calculations do not take into account any differences between migration and expulsion efficiencies of oil versus gas. [Back]

REFERENCES CITED IN CHAPTER B

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